Un.ted States EPA-600/7-81-025
Environmental Protection
Agency March 1981
&EPA Research and
Development
ENVIRONMENTAL ASPECTS OF
SYNFUEL UTILIZATION
Prepared for
All EPA Program and Regional Offices
Prepared by
Industrial Environmental Research
Laboratory
Research Triangle Park NC 27711
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into nine series. These nine broad cate-
gories were established to facilitate further development and application of en-
vironmental technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface in related fields
The nine series are:
1 Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
8. "Special" Reports
9. Miscellaneous Reports
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series Reports in this series result from the
effort funded under the 17-agency Federal Energy/Environment Research and
Development Program These studies relate to EPA's mission to protect the public
health and welfare from adverse effects of pollutants associated with energy sys-
tems. The goal of the Program is to assure the rapid development of domestic
energy supplies in an environmentally-compatible manner by providing the nec-
essary environmental data and control technology. Investigations include analy-
ses of the transport of energy-related pollutants and their health and ecological
effects, assessments of, and development of, control technologies for energy
systems: and integrated assessments of a wide range of energy-related environ-
mental issues.
EPA REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
for publication. Approval does not signify that the contents necessarily reflect
the views and policies of the Government, nor does mention of trade names or
commercial products constitute endorsement or recommendation for use.
This document is available to the public through the National Technical Informa-
tion Service, Springfield, Virginia 22161.
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EPA-600/7-81-025
March 1981
ENVIRONMENTAL ASPECTS
OF SYNFUEL UTILIZATION
by
M. Ghassemi and R. Iyer
TRW
ENVIRONMENTAL ENGINEERING DIVISION
Redondo Beach, CA 90278
EPA Contract No. 68-02-3174
Work Assignment No. 018
EPA Program Element No. CCZN1A
Project Officer: J. McSorley
Industrial Environmental Research Laboratory
Office of Environmental Engineering and Technology
Research Triangle Park, N.C. 27711
Prepared for:
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, D.C. 20460
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ABSTRACT
This study reviews the environmental concerns relating to the distri-
bution, handling, and end use of synfuel products likely to enter the
marketplace by the year 2000 and assigns priority rankings to these
products based on environmental concerns in order to aid EPA in focusing
its regulatory and research activities. Major products and by-products of
oil shale, coal liquefaction, and coal gasification technologies are
considered.
Based on current developmental activities, three likely scenarios for
shale- and coal-based synfuel plant build-up are projected. The type and
quantity of synfuel products and by-products likely to enter the market are
identified, and their regional market penetration is estimated. The
environmental analysis consists of a review of the available data on the
physical, chemical, and health effects characteristics of synfuel products
and the environmental significance of these characteristics; an analysis of
the potential environmental impacts and regional implications associated
with the production and use scenarios considered; and a ranking of the
products from the standpoint of environmental concerns and mitigation
requirements.
The results indicate that: (a) significant quantities of synfuel
products are expected to enter the marketplace during the next 20 years,
(b) large-scale transportation, distribution, and end use of certain
synfuel products can present significant threats to the environment and the
public health, (c) based on gross characteristics, synfuel products appear
to be similar to petroleum-based products, but detailed characterization
data are not available to permit judgements of their relative safety, and
(d) synfuel test and evaluation programs currently underway or planned
provide excellent opportunities for collecting some of the required
environmental data.
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CONTENTS
Abstract ii
Figures vi
Tables viii
Acknowledgement xii
1. INTRODUCTION 1
1.1 Background and an Overview of Current EPA Synthetic Fuels
Environmental Assessment Programs 1
1.2 Objective of the Synfuel Utilization Study 2
1.3 Methodology 2
1.4 Initial Examinations 4
1.5 Synfuel Utilization Projections 4
1.5.1 Types and Quantities of Synfuel Products/By-Products
Entering the Market 4
1.5.2 Market Analysis of Synfuel Products/By-Products • • 5
1.6 Environmental Analysis and Product Ranking 5
1.6.1 Development of Data Base on Synfuel Product
Characteristics 5
1.6.2 Analysis of Potential Areas of Environmental Concern
and Regional Implications of Synfuel Product
Utilization 6
1.6.3 Priority Ranking of Synfuel Products 6
1.7 Background Information 7
2. SYNFUEL PRODUCTION OVER THE NEXT TWENTY YEARS £
2.1 Synfuel Production Scenarios £
2.1.1 Perspectives for Synfuel Production Scenarios .... 8
2.1.2 Synfuel Industry Build-up Scenarios 20
2.1.3 Other Synfuel Production Projections 23
2.2 Synfuel Plant and Product Build-up Scenarios 25
2.2.1 Shale Oil 26
2.2.2 Coal Liquefaction and Gasification 36
3- MARKET ANALYSIS OF SYNFUEL PRODUCTS AND BY-PRODUCTS .
3.1 Likely Location of Synfuel Plants
o
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CONTENTS (Continued)
3.1.1 Oil Shale Plant Location 50
3.1.2 Coal Conversion Plant Location 50
3.2 Synfuel Product Utilization 53
3.2.1 Gaseous Products 56
3.2.2 Light Distillates 58
3.2.3 Middle Distillates 59
3.2.4 Residuals 59
3.2.5 Petrochemical Feedstocks and Other By-Products. ... 60
3.3 Regional Market Penetration of Synfuel Products 61
3.3.1 Shale Oil 61
3.3.2 Coal Gas 63
3.3.3 Coal Liquefaction Products 66
3.3.4 Petrochemical Feedstocks and Other By-Products. ... 73
3.3.5 Summary of Synfuel Product Utilization by Region . . 76
4, CHARACTERISTICS OF SYNFUEL PRODUCTS 99
4.1 Physical/Chemical Characteristics 99
4.1.1 Shale Oil Products 99
4.1.2 Direct Coal Liquefaction Products 101
4.1.3 Indirect Coal Liquefaction Products 103
4.1.4 Coal Gasification Products 104
4.1.5 Summary of the Data Currently Available and Data Gaps
from an Environmental Assessment Standpoint 106
4.2 Combustion Characteristics 107
4.2.1 Shale Oil Products 107
4.2.2 Direct Coal Liquefaction Products 109
4.2.3 Indirect Liquefaction Products 112
4.2.4 Coal Gasification Products 112
4.2.5 Summary of the Data Currently Available and the Data
Gaps from an Environmental Assessment Standpoint . . 114
4.3 Biological and Health Effects Characteristics 114
4.3.1 Shale Oil Products 114
4.3.2 Direct Liquefaction Products 116
4.3.3 Indirect Liquefaction Products 118
iv
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CONTENTS (Continued)
4.3.4 Coal Gasification Products 119
4.3.5 Summary of the Data Currently Available and Data . .
Gaps from an Environmental Assessment Standpoint . . .120
4.4 Relevant Comments from Potential Major Synfuel Suppliers
and Users 120
5- ENVIRONMENTAL ANALYSIS OF SYNFUEL UTILIZATION AND POTENTIAL
AREAS OF MAJOR ENVIRONMENTAL CONCERN 126
5.1 Significance of Reported Synfuel Products Characteristics 126
5.2 Estimated/Anticipated Characteristics of Various Synfuel
Products and Associated Environmental Concerns 129
5.3 Applicable Controls and Regulatory Considerations 139
5.3.1 Applicable Controls and Mitigation Measures .... 139
5.3.2 Significant Relevant Statutes and Regulations ... 140
5.4 Environmental Impacts Associated with Various Production
and Use Scenarios and Regional Considerations 145
5.4.1 Shale Oil Products 145
5.4.2 Low-/Medium-Btu Coal Gas Products 154
6. PRIORITY RANKING OF SYNFUEL PRODUCTS FROM THE STANDPOINT OF
ENVIRONMENTAL CONCERNS 157
6.1 Basis for Product Ranking 157
6.2 Attribute Rating Procedure 162
6.2.1 Exposure 162
6.2.2 Emission Factor 164
6.2.3 Toxic Hazard 164
6.2.4 Cost of Control 165
6.2.5 Adequacy of Existing Regulations 165
6.3 Products Ranking 168
7. DATA GAPS AND LIMITATIONS AND RELATED PROGRAMS 171
7.1 Major Factors Responsible for Data Gaps and Limitations . . 171
7.2 Specific Data Gaps and Limitations 173
7.3 Related Programs 174
7.3.1 Environmental and Health Effects Programs 175
7.3.2 Combustion Characteristics 175
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FIGURES
Number
1 Synfuel Industry Build-Up for the National Goal Scenario . . 21
2 Synfuel Industry Build-Up for the Nominal Production
Scenario 23
3 Synfuel Industry Build-Up for the Accelerated
Production Scenario 25
4 Oil Shale Product Build-Up for Scenario I 34
5 Oil Shale Product Build-Up for Scenario II 35
6 Oil Shale Product Build-Up for Scenario III 35
7 Coal Liquefaction Product Build-Up for Scenario I 46
8 Coal Liquefaction Product Build-Up for Scenario II 46
9 Coal Liquefaction Product Build-Up for Scenario III .... 47
10 Oil Shale Deposits Most Likely to be Used for Synfuel
Production 51
11 Coal Resources Most Likely to be Used for Synfuel Production 52
12 Likely Locations for Synthetic Fuel Plants 54
13 Synfuel Utilization During 1985-2000 62
14 Synfuel Production and Utilization Regions - Scenario II
1980-1987 78
15 Synfuel Production and Utilization Regions -
Scenario II - 1988-1992 82
16 Synfuel Production and Utilization Regions -
Scenario II - 1993-2000 89
17 Estimated Utilization Pattern for Shale Oil Products;
Scenario II, 1980-1987 Time Period 146
18 Estimated Utilization Pattern for Shale Oil Products;
Scenario II, 1908-1992 and 1993-2000 Time Period 147
,q Estimated Utilization Pattern for Low-/Hediun-Btu Gas;
Scenario II, 19CO-19C7 Time Period 148
VI
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FIGURES (Continued)
Number
20 Estimated Utilization Pattern for Indirect Coal
Liquefaction Products; Scenario II, 1988-1993 Time
Period 149
21 Estimated Utilization Pattern for Indirect Coal
Liquefaction Products; Scenario II, 1993-2000 Time
Period 150
22 Estimated Utilization Pattern for Direct Coal
Liquefaction Products; Scenario II, 1988-1992 Time
Period 152
23 Estimated Utilization Pattern for Direct Coal
Liquefaction Products; Scenario II, 1993-2000 Time
Period 152
VI1
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TABLES
Number
1 Synfuel Market Overview 3
2 U.S. Oil Shale Projects 10
3 Coal Gasifiers for High-, Medium-, and Low-BTU Gas .... 13
4 Status of other Coal Gasification Processes 14
5 Major Coal Liquefaction Processes 16
6 Synfuel Projections 24
7 Oil Shale Plant Build-Up, Scenario I 27
8 Oil Shale Plant Build-Up, Scenario II 28
9 Oil Shale Plant Build-Up, Scenario III 29
10 Current Permitting Status of Oil Shale Projects 30
11 Process Technologies Under Consideration 36
12 Coal Liquefaction Plant Build-Up for Scenario I 37
13 Coal Liquefaction Plant Build-Up for Scenario II 38
14 Coal Liquefaction Plant Build-Up for Scenario III 38
15 Coal Gasification Plant Build-Up for Scenario I 42
16 Coal Gasification Plant Build-Up for Scenario II 42
17 Coal Gasification Plant Build-Up for Scenario III .... 43
18 Maximum Anticipated Shale Oil Production Rate for
Scenario II 50
19 Number of Coal Conversion Plants Needed On-Stream to Meet
the Requirements of the Nominal Production Scenario -
Scenario II 55
20 Types and Quantities of Coal Conversion Products Produced
from Plants on Stream for the Nominal Production
Scenario - Scenario II 68
21 Comparison of Petrochemical Feedstocks and Other By-Products
Produced to Meet the Goals of Scenario II Vs. Scenario I
and Scenario III 74
22 Likely Utilization Patterns of Major Synfuel Products By
Regions-Scenario II, 1980-1987 Time Period (In MMBPD) ... 77
23 Likely Utilization Patterns of Major Synfuel Products By
Regions and by Sectors—Scenario II--1980-1987 Time
Period-Region VIII (In MMBPD) 79
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TABLES (Continued)
Number
24 Likely Utilization Patterns of Major Synfuel Products
by Regions and by Sectors—Scenario II—1980-1987 Time
Period-Region V (In MMBPD) 80
25 Likely Utilization Patterns of Major Synfuel Products by
EPA Regions-Scenario II--1988-1992 Time Period (In MMBPD). . 81
26 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario II--1988-1992 Time Period,
Region V (In MMBPD) 83
27 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario II--1988-1992 Time Period,
Region VIII (In MMBPD) 84
28 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario II—1988-1992 Time Period
Region X (In MMBPD) 85
29 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario II--1988-1992 Time Period
Region IX (In MMBPD) 86
30 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario II--1988-1992 Time Period
Region VII (In MMBPD) 87
31 Likely Utilization Patterns of Major Synfuel Projects by
EPA Regions, Scenario II — 1993-2000 Time Period (In MMBPD) 90
32 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario 11--1993-2000 Time Period
Region III (MMBPD) 91
33 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario 11--1993-2000 Time Period
Region IV (In MMBPD) 92
34 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario 11—1993-2000 Time Period
Region V (In MMBPD) 93
35 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario 11--1993-2000 Time Period
Region VI (In MMBPD) 94
36 Likely Utilization Patterns of Major Synfuel Products by
Regions and By Sectors—Scenario 11--1993-2000 Time Period
Region VIII (In MMBPD) 95
37 Likely Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario 11—1993-2000 Time Period
Region X (In MMBPD) 96
IX
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TABLES (Continued)
Number
38 Likely Utilization Patterns of Major Synfuel Products
by Regions and By Sectors—Scenario II—1993-2000 Time Period
Region VI (In MMBPD) 97
39 Like Utilization Patterns of Major Synfuel Products by
Regions and by Sectors—Scenario 11—1993-2000 Time Period
Region VII (In MMBPD) 93
40 Combustion Test Results for SRC II Fuel Oils 110
41 Combustion Test Results for H-Coal Fuels Ill
42 Combustion Test Results for EDS Coal Liquids 113
43 Summary of Health Effects Data for SRC II Products ana
(Where Available) for Petroleum Analogs 117
44- Health Effects Test Results for H-Coal Fuel Oils 113
45 Summary of Comments from Synfuel Suppliers on the
Relative Characteristics of Synfuels and Petroleum
Products 121
46 Summary of Comments from Potential Synfuel Users on
the Relative Characteristics of Synfuels and Petroleum
Products 123
47 Reported Known Differences in Chemical, Combustion, and
Health Effects Characteristics of Synfuel Products and
Their Petroleum Analogs 127
48 Sources and Nature of Environmental Concerns in the
Utilization of Shale Oil Products 130
49 Sources and Nature of Environmental Concerns in the
Utilization of Coal Liquefaction Products 133
50 Sources and Nature of Environmental Concerns in the
Utilization of Coal Gases 137
51 OSHA Standards for Materials Known or Suspected to be
Present in Lurgi SNG Plants 144
52 Quantity of Various Shale Oil Products in Relation to
Petroleum Analogs in the EPA Region of Maximum Shale
Oil Product Use and on a National Basis for Scenario II . 155
53 Estimated Quantities of Synfuel Products Used in the
U.S.: 1980-87 159
54 Estimated Quantity of Synfuel Products Used in the
U.S.: 1988-1992 160
55 Estimated Quantities of Synfuel Products Used in the
U.S.: 1993-2000 161
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TABLES (Continued)
Number
56 Relative Assessment of the Environmental Hazards
Associated with Synfuel Products and Petroleum Analogs . . 163
57 Priority Rankings of Synthetic Fuel Products 169
58 Chemical, Biological and Ecological Testing of Paraho/
Sohio Crude and Refined Shale Oil Suite 176
59 Health Effects Testing for Direct Coal Liquids 177
XI
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ACKNOWLEDGMENT
This study and the preparation of this report have involved
participation of professionals from two organizational elements of TRW:
Environmental Engineering Division, Redondo Beach, CA ; and Energy
Engineering Division, McLean, VA. The following individuals have
participated in the study:
Environmental Analysis
M. Ghassemi (Team Leader)
R. Scofield
R. Maddalone
S. Quinlivan
J. Cotter
L. Fargo
J. Dadiani
Synfuel Utilization Projections
R. Iyer (Team Leader)
E. Bohn
D. Dickehuth
M. Oyster
W. Parker
Interviews with Major Potential Suppliers/Users
E. Bohn
J. Cotter
J. Cowles
R. Iyer
K. Lewis
The project is deeply indepted to the EPA Project Officer, Mr. Joe
McSorley, for his continuing advice and guidance during the course of the
effort. Those on the project staff wish to express their gratitude to the
process developers who provided data for use in synfuel utilization
projections and the potential suppliers and users of synfuel products
listed in Appendix A who granted interviews expressing their views on
synfuel commercialization, product utilization, and related environmental
issues.
Special thanks are due to Ms. Judy Bolster and Ms. Carol Jeffrey for
their secretarial service, to Ms. Alice Lowthrop for her editorial review,
and to Mrs. Deborah Milanowski and Ms. Kathy Trujillo for Word Processing
services.
Xll
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SECTION 1
INTRODUCTION
1.1 BACKGROUND AND AN OVERVIEW OF CURRENT EPA SYNTHETIC FUELS
ENVIRONMENTAL ASSESSMENT PROGRAMS
The recognition of the limited availability of domestic supplies of
natural gas and crude oil and of the necessity to reduce the country's
dependence on foreign sources of energy have promoted significant
commitments by the U.S. government and the industry to the development of a
major domestic synthetic fuels industry. The government commitments are
demonstrated by the recent establishment of the U.S. Synthetic Fuels
Corporation to help and fund commercial projects and the Energy
Mobilization Board to speed permitting of energy facilities. The industry
has been heavily involved in the development, test and demonstration of
various energy technologies and is participating in the commercialization
program.
The establishment of a major synthetic fuels industry in the U.S. and
the widespread utilization of synfuel products present significant public
health and safety risks and a great potential for environmental
contamination. To meet these challenges, the U.S. Environmental Protection
Agency has accelerated and expanded its synthetic fuels environmental
programs and has taken steps to integrate internal agency planning
activities. Two policy groups, the Alternate Fuels Group (AFG) and the
Priority Energy Project Group (PEPG), have been formed under the Assistant
Administrator level EPA Energy Policy Committee. AFG will be responsible
for: (1) drafting the Agency's regulatory, permitting and research
strategy for synthetic and other alternate fuels; (2) coordinating the
preparation of environmental guidance for emerging fuels and technologies
for use by industry planners and permitting officials; and (3) developing
recommendations and overseeing the preparation and promulgation of new
environmental standards for these fuels and technologies as appropriate.
The Priority Energy Project Group will plan how EPA should relate and
respond to the activities of the Energy Mobilization Board. It will draft
the Agency's procedures and guidance for working with the Board and will
work with the Board, offering information and assistance on EPA permitting
and the effects of the Board activities on the review process.
The effort of AFG to date has included the formation of five working
groups that are involved in the preparation of Pollution Control Guidance
Documents (PCGD's) for major synthetic fuels technologies. The PCGD's will
provide guidance on available control technologies for multimedia waste
streams. Early development of environmental guidelines will: (1) allow
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their utilization in technology process design; (2) provide environmental
impact statement (EIS) and permit reviewers with information to ensure that
dischargers will be reasonably controlled in a cost-effective manner; and
(3) expedite EIS and permit application review. These factors should speed
commercialization of emerging synthetic fuels technologies while providing
environmental protection for currently known environmental effects. PCGD's
for gasification, direct and indirect liquefaction, and oil shale
technology are in various stages of completion; these efforts, which
receive inputs from EPA Program Offices, are being directed by the EPA
Industrial Environmental Research Laboratory in Research Triangle Park,
North Carolina (EPA/IERL-RTP) for the Coal Conversion Technologies; and by
the EPA Industrial Environmental Research Laboratory in Cincinnati, Ohio
(EPA/IERL-Ci) for the oil shale technology. In addition to the preparation
of PCGD's, EPA/IERL-RTP and EPA/IERL-Ci are currently involved in a number
of synthetic fuel environmental assessment programs involving process
technology data base development, control technology assessment, and
environmental data acquisition via source test and evaluation at synfuel
facilities.
PCGD's and nearly all other current EPA synfuel-related environmental
assessment programs primarily focus on the technologies for the production
of synthetic fuels. The study described in this report, which was
sponsored by the EPA/IERL-RTP, constitutes the first major effort by EPA to
identify and examine environmental concerns that would be associated with
the projected wide-scale distribution, handling, and end use of synfuel
products. A related program, which is currently in progress and which is
sponsored jointly by EPA/IERL-RTP and EPA Office of Planning and
Management, will extend the present study to an analysis of the tradeoffs
of various product slates for minimizing environmental impacts associated
with product handling, distribution, and utilization.
1.2 OBJECTIVE OF THE SYNFUEL UTILIZATION STUDY
Several synfuel technologies are under consideration for commercial
production. A wide range of synfuel products is expected to be produced
and utilized in a broad category of end uses (Table 1).
The objective of this study was to evaluate a broad range of
environmental concerns relating to synfuel utilization and assign them
priority rankings to aid EPA in focusing its regulatory and research
activities. The study includes the entire market infrastructure, which
will eventually comprise synfuel upgrading; product distribution and
storage; and product consumption.
1.3 METHODOLOGY
The study methodology was based on the development of a priority
matrix of environmental concerns and criteria, which were evaluated for
each of the synfuel process technologies and products indicated in Table 1.
The elements of this priority matrix include:
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TABLE 1. SYNFUEL MARKET OVERVIEW
What Technologies Produce Synfuels?
What Major Products/
Byproducts Will They
Make?
Where Will The Products/
Byproducts Be Used?
Hhat Are The Relative
Potential Exposure Levels
to "he Products?
OIL SHALE:
Numerous Retor-
ting processes,
Including Tosco,
Paraho, Union,
Occidental
Syncrude upgraded and
refined to yield:
Gasoline
Jet Fuel
Diesel Fuel
Residuals
DIRECT COAL LIQUEFACTION: SRC-11
Exxon Donor
Sol vent
H-Coal
LPG
Naphtha
Fuel Oil
LPG
Naphtha
Fuel Oil
Solvent
Naphtha
Fuel Oil
LPG
• Commercial and military
transportation, incluo
ing highway vehicles,
aircraft, ships
« Utility and industrial
boilers
• Commercial and resif
dentlal heating
l Industrial lubricants
Low for transport of
crude shale to refinery;
moderate during refining
increased exposure level
when used in transporta-
tion sources and space
heating and end use as
boiler fuel
• Utility and Industrial
boilers
* Commercial and residen-
tial heating
• Chemical feedstocks
* Utility and industrial
boilers
• Commercial and resi-
dential heating
* Paint thinners
« Utility and industrial
boilers
« Commercial and resi-
dential heating
Low for LPG, Naphtha as
feedstocks. Moderate
exposure for fuel oils at
industrial sites with
exposure for fuel oils
at industrial sites with
exposure increasing when
used in space heating
INDIRECT COAL LIQUEFACTION: Fischer-Tropsch
H-Gasoline
Methanol
Gasoline
LPG
Diesel Fuel
Heavy Fuel Oil
Medium Stu Gas
SNG
Tar Oils3
Phenols
Gasoline
Fuel Grade Methanol
• Commercial and military
transportation
• Utility and industrial
boilers
• Commercial and resi-
dential heating
t Chemical feedstocks
• Agriculture uses
t Commercial and military
transportation
• Commercial and military
transportation
t Chemical feedstocks
Moderate exposure when fuels
used in transportation so-
urces and boilers. Low to
moderate exposure is also
estimated when products
used as chemical feedstocks
HIGH 8TU COAL GASIFICATION:
Numerous Processes,
Including Lurgi,
Coed-Cogas, Texaco,
Shell-Koppers
SNGU
i Commercial and resi-
dential heating
Very low - similar to
current distribution of
natural gas
MEDIUM BTU COAL GASIFICATION: Numerous Processes
Medium Btu Gas
Low Btu Gas
• Captive fuel use for
industrial heating and
chemical feedstocks
Very low for captive use;
moderate exposure for fuel
use
aOnly representative byproducts are indicated
"Substitute Natural Gas
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0
Amount of synthetic fuel product in the market (at any time)
• Exposure created by transport, storage, and end use of a
designated quantity of product
• Emission factors (air, water, land) related to product transport,
storage, and end use
• Toxic hazards associated with the products and their combustion
products
• Cost of pollution controls that would be required to mitigate the
exposure
• Regulatory protection that would be offered by existing or
planned environmental regulations.
Environmental evaluations of new product use emphasize the element of
risk associated with exposure. There is already an implicit acceptance of
the risk of conventional petroleum and natural gas utilization. Therefore,
it seems logical that any assessment of synfuel utilization risk should be
relative to the existing use of conventional fuels.
1.4 INITIAL EXAMINATIONS
First, sets of background information were compiled that included data
on those synfuel technologies considered mature enough for possible
commercialization by the 1990s. These technologies are coal gasification
(high-Btu, medium-Btu, low-Btu), coal liquefaction (indirect and direct)
and oil shale retorting. Production rates for the particular synthetic
fuels were projected based on various production forecasts by potential
synfuel producers or government agencies. Finally, the environmental
exposures of the utilization systems were scoped, control options were
briefly considered, and options for EPA actions were noted. The results of
this initial examination were published under the Problem-Oriented Report
Title "Utilization of Synthetic Fuels: An Environmental Perspective" by
Industrial Environmental Research Laboratory/Research Triangle Park (August
1980).
1.5 SYNFUEL UTILIZATION PROJECTIONS
1.5.1 Types and Quantities of Synfuel Products/Bv-Products Entering the
Market
Three specific scenarios were chosen to define possible synfuel
utilization systems of the 1990's that would derive from the most likely
buildup rates for the most mature synfuel processes at the probable
production sites.
0 A national goal scenario driven by federal incentives
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0 A nominal production or most likely scenario
• An accelerated production scenario representing an upper bound
for industry buildup.
Those refined or processed products likely to be produced from the
major synfuel plant product streams were evaluated to yield the types and
quantities of synfuel products and by-products entering the market.
Recognizing that plant mix, product split, distribution systems, and
end use may vary from scenario to scenario, the differences among the three
scenarios were specifically identified.
1.5.2 Market Analysis of Synfuel Products/By-Products
The penetration of synfuel products and by-products into the existing
marketing system for conventional fuels was analyzed. For this purpose, a
survey of the existing marketing system infrastructure established the type
and relative quantities of petroleum-based products and by-products that are
in commerce today. This infrastructure served as a baseline system into
which oil shale and coal-derived synfuel products and by-oroducts were
introduced as they become available. The existing baseline system facili-
tated comparison of product quantities, modes of transport, exposures (by
geographical areas), emissions, toxic characteristics, and the control and
regulatory framework for environmental protection.
Also a limited set of interviews was held with potential synfuel
product users and producers to determine their plans for production and use
of synfuel products. Representative producers of each synfuel type (oil
shale, coal gasification, coal liquefaction), personnel from DOE energy
technology centers, and representatives of end-users were interviewed. The
interview results were incorporated into the market analysis.
The analysis included:
• Identification of plant types, their likely location, and timing
t Identification of synfuel product/by-product end uses
• Evaluation of distribution, handling, and storage systems for the
major product slates
• Description of end use applications and geographical
distribution, including transportation, utility, industrial, and
commercial/residential sectors.
1.6 ENVIRONMENTAL ANALYSIS AND PRODUCT RANKING
1.6.1 Development of Data Base on Synfuel Product Characteristics
To develop the data base for analyzing environmental implications of
synfuel product end uses, the reported data on physical and chemical
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properties and health effects and combustion characteristics of synfuel
products (and where available of analogous petroleum and natural gas
products) were reviewed, the limitations of the available data, which
should be clearly understood in comparihg synfuels with conventional fuels
from an end use environmental standpoint, and the key relevant on-going and
planned programs which would be expected to generate some of the needed
data were identified.
1.6.2 Analysis of Potential Areas of Environmental Concern and Regional
Implications of Synfuel Product Utilization
The potential areas of environmental concern in synfuel utilization
were identified in the light of the significance of reported or estimated
product characteristics. The known and estimated environmental
significance of product properties were then related to the product
utilization scenarios developed previously and potential environmental
areas requiring more immediate attention were highlighted. In general, the
environmental analysis was in "relative" rather than "absolute" terms in
that properties and use impacts of synfuel products were not considered in
themselves but rather were reviewed in comparison with those for the
petroleum analogs. Some of the control measures and regulatory
considerations for the mitigation of the major environmental concerns for
various anticipated product uses were identified. Six major Federal
environmental statutes which would have bearings on the environmental
concerns and mitigation measures were briefly reviewed.
1.6.3 Priority Ranking of Synfuel Products
A priority ranking system was developed and used to rank synfuel
products from the standpoint of end use environmental concerns. The system
takes into account;
• Environmentally significant characteristics of synfuel products
relative to those of petroleum analogs, based on consideraions of
exposure potential, combustive and evaporative emissions, toxic
hazards, cost of control and the extent of regulatory protections
under key existing environmental legislations. Products for
which the environmental risks and control needs are greater and
for which less protections can be anticipated under existing
regulations were given a higher ranking.
• The estimated quantity of products used, both in absolute terms
and as percentages of the total (synfuel and petroleum) used
nationwide and in the regions of maximum use. The greater the
amount of the product used and the percentages of usage, the
greater is the potential of presenting environmental hazards and
hence a higher positive ranking.
• Considerable scientific and engineering judgement. Because of
the lack of a solid data base, heavy reliance was placed on the
professional judgement of experts most familiar with the domestic
-------
energy supply and demand picture, synfuel production/refining
technologies, expected environmental characteristics of synfuel
products, applicable controls and regulatory needs.
Based on the above considerations, synfuel products were ranked into
threee groups: those eliciting the most concern (ranked as "1"), those
indicating the ''modest" concern (ranked as "2") and those generating a
"low" level of concern at the present time (ranked as "3").
1.7 Background Information
A substantial body of information was used to derive the analyses and
conclusions contained in this report. This background information is
contained in the appendices:
Appendix A. Interviews with Potential Suppliers and Users of Synfuel
Products
Appendix B. Commercial Coal Liquefaction and Gasification Projects
Appendix C. Cooperative Agreements and Feasibility Study Grants for
Synfuels
Appendix D. Baseline Petroleum and Natural Gas System
Appendix E.
Physical and Chemical Characterization of Synfuel
Products
Appendix F. Combustion Products and Use Properties of Synthetic
Fuels
Appendix G. Health Effects Test Results for Synthetic Fuels
-------
SECTION 2
SYNFUEL PRODUCTION OVER THE NEXT TWENTY YEARS
2.1 SYNFUEL PRODUCTION SCENARIOS
To obtain an environmental perspective of synfuels utilization, three
scenarios of synfuel industry buildup rates to the year 2000 were devel-
oped: (1) The national goals scenario driven by federal incentives; (2) a
nominal production or most likely scenario; and (3) an accelerated pro-
duction scenario representing an upper bound for industry buildup. Based
on these scenarios, the product market for synfuels and their possible
environmental impacts are discussed in Sections 3, 4, and 5, respectively.
2.1.1 Perspectives for Synfuel Production Scenarios
2.1.1.1 History and Status of Synfuel Technologies
The term synfuel has become synonymous with any combustible
nonpetroleum fuel source, including coal- and shale-derived fuels and
feedstocks as well as those derived from agricultural products such as
grain, wood, and cellulose. However, industry has become increasingly more
interested in those synfuel technologies with products that are easily sub-
stituted for petroleum and natural gas--coal- and shale-derived products.
The following discussion is limited to these products.
Shale Oil Technology - History and Status
The use of oil shale as a fuel resource predates the large-scale use
of conventional petroleum by several centuries. In the past 150 years,
commercial industries have existed in Scotland, France, Germany, Spain,
South Africa, Australia, and the United States. The U.S. oil shale indus-
try was an important part of the nation's energy economy before the first
oil well was drilled. At least 50 commercial plants for extraction of fuel
oil from eastern oil shales existed before 1859; but the industry dis-
appeared shortly after commercial petroleum production began. However, the
Synthetic Liquid Fuels Act was passed just before the end of Second World
War, and soon after its passage the United States Bureau of Mines (USBM)
began a comprehensive R&D program that has continued to the present day,
although oversight authority has been transferred to the Department of
Energy. One of USBM's most significant early acts was to establish a
research facility at Anvil Points on the Naval Oil Shale Reserve near
Rifle, Colorado. In 1973, the facility was leased by Development
Engineering Inc. (DEI), which operated it for five years. During this time
the Paraho retorting process was developed. DEI used the facility to
produce over 100,000 barrels of shale oil for refining studies.
8
-------
As a direct substitute for large volumes of liquid fuels, oil shale
technology is perhaps closest to commercialization in the U.S. Several
consortia and companies have been engaged in the development of shale oil
technology for some time and have established shale oil projects located in
prime shale areas of Colorado and Utah (Table 2).
Many technologies for the extraction of kerogen (a waxy organic
material) from shale are being developed and tested. Most involve heating
shale to about 480°C and pyrolyzing the kerogen into a viscous liquid
called shale oil. They differ in the manner in which this heating process
is accomplished: surface retorting, in situ retorting, or modified in situ
retorting.
In surface retorting, oil shale is mined, crushed to the proper size,
and then fed to a large kiln for heating. Several surface retorting pro-
cesses are under development that differ primarily in the heating method
used. Internal-combustion retorting heats shale by the circulation of hot
gases that are produced inside the retort by the combustion of residual
carbons in the shale. Gas-cycle retorts used by Union Oil heat the shale
by circulating externally heated fluids; no combustion occurs inside the
retort. In solid-heat-carrier retorting, hot solids are heated outside the
retort and cycled through the shale. For example, the TOSCO process uses
ceramic balls as the heat carrier.
In situ retorting pyrolyzes oil shale while it is still in the ground.
The shale bed is ignited and sustained by injection wells, the shale is
pyrolyzed, and the oil produced is pumped out of the retort volume through
a production well. The spent shale remains in place. For successful in
situ retorting, the shale bed must be made permeable to the flow of heat
and product oil; various techniques of bed leaching or fracturing are
employed. The difficulty of creating a permeable shale bed has led to the
development of modified in situ processes. Vertical modified in situ
(VMIS) retorting removes a portion of the shale from the bottom of the
deposit and fractures the remaining shale to create a chimney of shale
rubble. The shale in this chimney is retorted from top to bottom.
Occidental Oil Company has been testing VMIS retorting on shales at Logan
Wash and Piceance Creek Basin in Colorado. Horizontal modified in situ
retorting lifts the overburden in some cases, and fractures the shale seam
to retort the shale from side to side. Geokinetics, Inc. is developing
this technique in Utah.
The technology for surface retorting is more advanced than that for in
situ retorting, because process variables are easier to monitor and control
in above-ground retorts than in underground retorts. However, large-scale
commercial surface retorting requires large-scale oil shale mining, haul-
ing, and crushing; and large-scale disposal of spent shale. It is also
limited to that portion of the shale resources that is mineable. In situ
retorting without mining is applicable to a greater variety of shale beds,
and eliminates the requirements for handling, crushing, and spent shale
disposal. However, attempts to demonstrate this technology have identified
-------
TABLE 2. U.S. OIL SHALE PROJECTS
Project
Chevron
Colony (TOSCO, EXXON C)
Equity Oil
GeoMnetlcs, Inc.
Location
Plceance Basin
Parachute Creek
Plceance Creek
Ulnta County
Technology
Undecided
Surface retorting
Solution Injection, modified
In-sltu
Horizontal modified In-sltu
Production
Capacity Goal
(bbl/day)
50,000
47,000
-
7-13
2 ,000-5 ,000
Status
Technical assessment phase.
Construction of commercial mod-
ules scheduled for 1980.
Steam-Injection feasibility
Several small retorts successfully
burned; work on larger retorts In
Getty Oil
Mobil
Occidental Oil
Occidental Oil - Tenneco
Paraho (Development Engineering,
Inc.)
Rio Blanco (Gulf, Amoco)
Superior Oil
TOSCO-Sand Mash
Union Oil
White River (Sohlo, Sunoco,
Phillips)
Plceance Basin
Plceance Basin
Logan Wash
Tract C-b,
Plceance Basin
Anvil Points
Tract C-a,
Plceance Basin
Plceance Creek
Ulnta Basin
Parachute Creek
Surface thermal extraction
Undecided
Vertical modified In-sltu
Vertical modified In-sltu
Surface retorting
Vertical modified In-sltu,
surface retorting
Multlmlneral recovery, sur-
face retorting
Modified In-situ, surface
retorting
Surface retorting
Tracts U-a and U-b, Modified
-------
many development problems. Modified in situ processes are a compromise;
they require some mining and handling, but offer more process control and
easier development.
The crude shale oil produced by retorting will be upgraded by further
processing. This upgraded shale, or syncrude, will be used as a refinery
feedstock or boiler fuel. It is well suited for refining into middle
distillate fuels. If hydrocrack ing is chosen for the refining process, the
yield and range of products is particularly desirable: motor gasoline 17
percent; jet fuel 20 percent; diesel fuel 54 percent; and residuals 9
percent.
Several oil shale projects will begin operation during the 1980s. The
technologies, which are proprietary in many cases, appear to be suffici-
ently mature to move ahead to commercialization. Several retorts have been
successfully operated by Geokinetics, Inc., Occidental Oil, Paraho, Union,
and TOSCO. Colony, Union Oil, and Occidental Oil have announced plans to
begin commercial development in 1980. All technologies have been
demonstrated at pilot scale or larger.
Coal Gasification - History and Status
Coal gasification processes have been used in Europe and America since
the early nineteenth century to supply the fuel needed to light the streets
in major cities. This fuel, known as town gas or, sometimes, as water
gas, was made by reacting coal with steam. However, the process was expen-
sive and troublesome to maintain, efficiencies were low, and operation was
inevitably dirty. Despite its drawbacks, gas made from coal played a major
role in the U.S. well into the 1900s, particularly in supplying markets
that were far from natural gas fields but near coal deposits. As late as
1932, the residential gas market in the eastern U.S. was supplied mainly
with synthetic gas made from coal. But when long-distance pipelines were
constructed during World War II, cheaper natural gas became more convenient
nationwide and the use of coa1 gas in the U.S. declined.
Most coal gasifiers react coal, steam, and oxygen to produce a gas
containing carbon monoxide, carbon dioxide, and hydrogen. When air is used
as the oxygen source, the product gas contains up to 50 percent nitrogen
and is referred to as low-Btu gas because its heat of combustion is only 80
to 150 Btu/standard cubic feet (scf). Synthesis gas or medium-Btu gas
ranges from 300 to 500 Btu/scf.
Low-Btu gas is used as a fuel gas near its point of generation because
its low heating value makes it uneconomical to distribute over long dis-
tances. Medium-Btu gas can be used as a fuel gas and transported economi-
cally over distances of up to 200 miles. It can also be used as a chemical
feedstock for the production of methanol or gasoline, or can be converted
catalytically to substitute natural gas (SNG), having a heating value of
about 1,000 Btu/scf. Medium-Btu gasification is an integral part of all
indirect liquefaction technologies.
11
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The many coal gasification technologies differ in design and
operation, depending upon the type of coal used and the product desired.
High- and medium-Btu gasification technologies using noncaking U.S. western
coals are relatively well developed. Severe operational problems are
encountered with commercially available gasifiers in processing caking
coal, such as that found in the eastern U.S. Several gasification tech-
nologies for high- and medium-Btu gases are under development (Table 3).
Many additional processes are being tested, but are at less advanced stages
of development (Table 4).
A fixed-bed gasifier, such as the Lurgi, feeds coal to the top of the
gasifier. The descending coal is successively dried, devolatilized, and
gasified in contact with gases rising from the bottom. Steam and oxygen
are introduced at the bottom of the gasifier, and solid ash is removed
through an ash lock. In some gasifiers, such as the British Gas Company
(BGC) Lurgi, the temperature at the bottom of the bed is sufficient to melt
the ash, allowing its removal as molten slag. The slagging feature pro-
vides a distinct advantage in contending with the caking characteristics of
eastern U.S. coals.
Lurgi's high-pressure operation, in conjunction with relatively low
gasification temperatures, favors the formation of significant quantities
of methane in the gasifier, and enhances the heating value of the product.
These conditions also favor production of by-products such as tars and
impurities like phenols, organic nitrogen compounds, and sulfur compounds.
In fluid-bed gasifiers currently under development, high-velocity
gases pass up through the bed to fluidize the coal, providing excellent
mixing and temperature uniformity throughout the reactor. Operability with
eastern U.S. caking coals, as well as low tar production and tolerance to
upsets in fuel rates, have been demonstrated at the pilot scale for both
the Westinghouse and U-Gas gasifiers.
The Texaco and Koppers-Totzek gasifiers are representative of
entrained-bed technology in which the solid particles are concurrently
entrained in the gaseous flow. Flame temperatures range from 1370 to
1925°C, resulting in melting of the coal ash with minimum production of
impurities. Entrained-flow gasifiers, which can operate with caking coals,
may be favored for the production of synthesis gas for indirect liquefac-
tion. However, compared to fluid-bed gasifiers, they have very low carbon
holdup capability in the reactor and, therefore, have limited safeguard
against possible formation of an explosive mixture in the reactor in case
of coal feed interruption.
There has been extensive commercial experience in the U.S. with low-
Btu coal gasification technologies operating near atmospheric pressure.
However, these applications have been limited to small-scale captive
applications for providing industrial process heat and space heating. For
example, the Wellman-Galusha gasifier designed for atmospheric pressure
operation was used extensively by industry years before pipeline-supplied
natural gas was readily available at comparatively lower cost. Pressurized
12
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TABLE 3. COAL GASIFIERS FOR HIGH-, MEDIUM-, AND LOW-BTU GAS
Process
lurgl Dry Ash
British Gas
Company (BGC)
Lurgl
Texaco
U-Gas Institute
of Gas Tech-
nology (IGT)
Westlnghouse
Shell Koppers
(Coppers- Totiek
Process Type
Pressurized fixed
bed, dry bottom
Pressurized Fixed
bed slagging bottom
Pressurized single
stage entrained,
slurry feed
Pressurized fluid
bed, ash
agglomerating
Pressurized single
stage fluid bed,
ash agglomerating
Pressurized entrained,
dry feed
Atmospheric entrained,
dry feed
Potential
Products
Substitute Natural Gas
(SNG, also known as High*
Btu Gas). Med1um-Btu
Fuel* Gas, Low-Btu Fuel
Gas
SNG, Medlum-Btu Fuel
Gas. Low-Btu Fuel Gas
SNG, Mod1um-8tu
Synthesis Gas, Low-
Btu Fuel Gas
SNG, Medlum.Btu Fuel
Gas, low.Btu Fuel
Gas
SNG. Mcdlum-Btu Fuel
Gas, Low-Btu Fuel
Gas
Medtum.Btb
Synthesis Gas.
Low-Btu Fuel Gas
Med1um*Btu
Synthesis Gas,
Low- Btu Fuel Gas
Host Suitable
Products
SNG. Medlum-fltu Fuel
Gas. Low-Btu Fuel Gas
SNG, Medlum-Btu Fuel
Gas, Low-Btu Fuel
Gas
MedlunuBtu Synthesis6
Gas
Medium- Btu Fuel Gas
SNG. Medlum.Btu Fuel
Gas
Hed1um~8tu
Synthesis Gas
Hedlum.Btu
Synthesis Gas
Status
40 years of contnerclal development and 14
commercial plants located In Australia,
Germany, UK. India, Pakistan, South Africa,
Korea. Average module size 800 tons/day
(2000 BOE)C
790 tons/day (of coal) (2000 BOE) pilot
plant tested In Uestfleld, Scotland
160 ton/day (400 BOE) plant operating In
West Germany
14000 tons/day of coal plant (35000 BOE)
producing Hedlum.Btu Fuel Gas, under
design for construction In Tennessee
15 ton/day (40 BOE) process development
unit, under testing at Waltz Mill, Pa.
150 ton/day (400 BOE) pilot plant In oper-
ation In W. Germany. 1,000 ton/day
scheduled In 1983/1984.
1.000 ton/day (2500 BOE) plant In opera-
tion In South Africa for the production
of ammonia
U>
a Medlum-fltu Gas with significant concentration of methane Is more suitable for use as fuel, and therefore Identified as MedlunvBtu Fuel Gas.
b Hedlum-Btu Gas with low concentration of methane Is more suitable for chemical synthesis,ard therefore Identified as Hedlum-Btu Synthesis
Gas
c BOE - Barrels per day of oil equivalent
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TABLE 4. STATUS OF OTHER COAL GASIFICATION PROCESSES
DEMONSTRATION PLANTS
HYGAS
COED-COGAS
U-GAS
SCALE
(tons/day
coal feed)
7340
2210
3160
STATUS
Conceptual Design
Detailed Design
Detailed D<
"sign
PILOT PLANTS/PDUs
BELL HIGH MASS FLUX 6
BIGAS 120
COMBUSTION ENGINEERING 5
DOW 24
EXXON CATALYTIC 100
GEGAS 24
HYDRANE 4
MOLTEN SALT 24
MOUNTAIN FUEL 12
SYNTHANE 72
TRI-GAS 1
Operational
Operational
Operational
Under Construction
Proposed
Operational
Proposed
Operational
Proposed
Mothbalied
Operational
Conceptual design incorporates all important details of major unit
areas in the plant. Material balances are provided around all major
unit areas. (Unit area is a section of the plant consisting of
several components integrated to perform a single transformation on
the product stream. Examples are gasification, raw gas cooling, gas
cleanup, or methanation.)
All equipment and detailed pipeline diagrams are prepared as part of
detailed design. In addition, detailed material balances are prepared
for each piece of equipment.
cThe plant is either operating or has operated successfully in the
past.
14
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gasification processes capable of yielding high-Btu gas for pipelines and
medium-Btu gas for chemical feedstocks are less well developed, with the
exception of the Lurgi fixed-bed process. The Lurgi process is based on 40
years of commercial development at 14 commercial plants that are located in
Australia, Germany, U.K., Korea, India, Pakistan, and South Africa. A
great deal of interest in the Lurgi technology is emerging in the U.S., and
plans for SNG production have been announced by several pipeline and gas
utility companies. Several projects using the Texaco process for captive
applications (chemical feedstocks and onsite power generation) are in the
planning and design stage with at least one project (Tennessee-Eastman)
scheduled for construction in 1980.
Direct and Indirect Coal Liquefaction - History and Status
Coal liquefaction processes have been developed more recently than
coal gasification processes. Before World War II, a number of coal lique-
faction plants were built in Germany, in anticipation that oil might not be
available. Complex, bulky, and expensive as they were, these processes
helped to fuel the German war machine. They produced up to 100,000 barrels
of transportation fuels a day at the height of the war. Small-scale feasi-
bility studies of German technology were conducted in the U.S. during the
1930s, but the effort was largely ignored because of the discovery of
cheaper east Texas oil in 1930. In 1940, U.S. interest revived somewhat,
and Congress passed the Synthetic Liquid Fuels Act. The Act provided $85
million in research funds, and two experimental plants were built and
operated until the program ended in 1955. Then, just as in 1930, another
large oil discovery, this time in the Middle East, killed interest in coal
liquids. However, in 1950, South Africa, realizing its total dependence on
imported oil for liquid fuels, initiated plans for a 10,000-barrel-per-day
plant based on German liquefaction technology. This plant, SASOL I, has
been operational since 1956. Today this plant and its sister plant, SASOL
II, are the only large-scale commercial facilities in the world producing
liquid fuel from coal.
There are two basic types of liquefaction processes — direct and
indirect. For direct liquefaction, coal, hydrogen, and a coal-derived oil
are mixed at high temperature and pressure. Under these conditions the
coal decomposes and the fragments react with hydrogen to form additional
derived oil, which is separated from the unreacted solids and further
refined to produce usable liquid fuels. Indirect liquefaction pro-
cesses react the coal with oxygen and steam in a gasifier to produce a
synthesis gas composed mainly of carbon monoxide, carbon dioxide, and
hydrogen. After the carbon dioxide and other impurities are removed from
the gas, the carbon monoxide and hydrogen are chemically combined in a
catalytic reactor to produce liquid products for use as chemical feedstocks
or liquid fuels.
There are three major direct coal liquefaction processes currently
under development: SRC, Exxon Donor Solvent (EDS), and H-Coal (Table 5).
These processes differ mainly in the way the hydrogen is made to react with
coal fragments to produce the unrefined coal liquids. In the SRC process,
15
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TABLE 5. MAJOR COAL LIQUEFACTION PROCESSES
PROCESS
PROCESS TYPE
PRODUCTS
STATUS
Solvent Refined Coal,
SRC II (Gulf Oil)
H-Coal
(Hydrocarbon Research,
Inc.)
Exxon Donor Solvent, EDS
(Exxon Research and
Engineering Company)
Flscher-Tropsch
(M.H. Kellogg/Lurgi)
Mobil-M
Direct liquefaction by sol-
vent extraction: coal dis-
solved 1n solvent, slurry
recycled, catalytic hydro-
genatlon
Direct liquefaction by
catalytic hydrogenation,
ebullated catalyst bed
Direct liquefaction by
extraction and catalytic
hydrogenation of recycled
donor solvent
Indirect liquefaction,
liquefaction of synthesis
gas in a fluid bed
catalytic converter
Indirect liquefaction,
liquefaction of synthesis
gas in fixed bed using
molecular size-specific
zeolite catalyst
LPG
Naphtha
Fuel Oil
SNG
Naphtha
Fuel Oil
Propane
Butane
Naphtha
Fuel Oil
Gasoline
LPG
Diesel Fuel
Heavy Fuel 011
Medium Btu Gas
SNG
Gasoline
LPG
Pilot Plant under operation.
6700 ton/day of coal (20,000
barrels/day of oil equivalent)
demonstration module under
design and schedule for oper-
ation in 1984-1985
600 ton/day (1400 barrels/
day of oil equivalent)
pilot plant under construc-
tion, testing will begin
1n 1980. Plant 1s located
at Catlettsburg, Kentucky
250 ton/day (500 barrels/
day of oil equivalent)
pilot plant under construc-
tion, testing will begin in
1980. Plant 1s located at
Baytown, Texas
SASOL I, 800 tons/day, pro-
ducing over 10,000 bbl day of
liquids in commercial produc-
tion since 1956. SASOL II,
40,000 tons/day, producing
over 50,000 bbl day of liq-
uids has been completed and
will begin start-up in 1980.
SASOL III with approximately
the same capacity as SASOL II
is currently being plan-
ned.
Commercial scale plant to
produce 12,500 barrels of
gasoline using reformed
natural gas 1s planned for
New Zealand in 1984-1985
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the coal feed and hydrogen are mixed with a process recycle stream that
contains unreacted coal ash as well as coal-derived oil. The iron pyrite
in the unreacted ash catalyzes the reaction between the coal fragments and
hydrogen. In the EDS process, the coal feed and hydrogen are mixed with a
specially hydrogenated coal oil called the donor solvent. The hydrogen
added to the coal fragments is provided by the solvent and the hydrogen
gas mixed in the reactor. The donor solvent is made by catalytically
hydrogenating coal-derived oil using conventional petroleum refinery
hydrotreating technology. In the H-Coal process, the unreacted coal and
hydrogen are mixed with coal-derived oil and an added solid catalyst in a
special reactor referred to as an ebullated bed.
After the gases and distillable liquid products have been separated
from the reactor effluent, the remaining "bottoms" material is processed.
This material contains significant quantities of heavy hydrocarbons that
must be efficiently utilized to enhance process economics. The principal
bottoms processing step under consideration for the EDS process is
FLEXICOKING, which consists of thermal cracking of the bottoms to produce
additional liquids and coke. The coke is subsequently gasified to produce
plant fuel gas or hydrogen for the liquefaction step. Bottoms processing
for the SRC and H-Coal processes probably will be partial oxidation (i.e.,
gasification) to produce hydrogen for the liquefaction step.
There are two major indirect coal liquefaction processes: Fischer-
Tropsch, which is commercial now in South Africa; and Mobil-M, which is
expected to be commercial in 1983-84. In the Fischer-Tropsch process, the
purified synthesis gas from the gasifier is reacted over an iron catalyst
to produce a broad range of products extending from lightweight gases to
heavy fuel oil. This broad product distribution is generally considered to
be a disadvantage where large yields of gasoline are desired. Improved
catalysts are currently being developed at the bench scale to maximize the
yield of gasoline-range hydrocarbons. In the Mobil-M process, the syn-
thesis gas is first converted to methanol using commercially available
technology, and then the methanol is catalytically converted to high-octane
gasoline over a molecular-size-specific zeolite catalyst.
Production of methanol from medium-Btu gas, which essentially consists
of CO and hL, could be categorized as an indirect liquefaction process;
however, no new process development is necessary for this step. Currently
methanol is made from CO and HL produced by reforming natural gas.
Indirect coal liquefaction is successfully operating on a commercial
scale at the SASOL I plant in South Africa using the Fischer-Tropsch tech-
nology. The SASOL I plant produces gasoline, middle distillates (jet fuel,
diesel oil), and heavy oil. SASOL II, producing 50,000 barrels per day of
coal-derived liquids, has been completed and will begin operation later in
1980. Active interest in this technology has developed and plans to
license and construct similar plants in the U.S. are progressing. There is
strong interest in the Mobil-M gasoline indirect process because of its
17
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attractive high-octane gasoline yield. A commercial-scale plant producing
12,500 barrels per day of gasoline is planned for operation in New Zealand
by 1985.
Direct coal liquefaction technologies are in various stages of
development. SRC I and II processes have been tested at the pilot-plant
level and are entering into the demonstration-plant stage. The SRC I
process produces primarily a solid product with a small amount of useful
liquid product; whereas the SRC II process produces primarily liquid
products.
Large pilot plants are currently under construction for testing of the
H-Coal and EDS processes. These plants are located at Catlettsburg,
Kentucky and Baytown, Texas, respectively.
In addition to these major coal liquefaction technologies, several
other processes, including the DOW process, Riser Cracking, Synthoil, and
the Zinc Halide process, have received attention. All have been tested in
small-scale units.
2.1.1.2 Incentives for Synfuel Development
The primary incentive for synfuel development is the imbalance
between domestic supply and demand for petroleum liquids and natural gas.
The long-term decline in domestic oil production coupled with increased
demand has resulted in a level of oil imports of 9 million barrels per day
(MMBPD), or about 50 pecrcent of U.S. consumption. The proven domestic
reserves of natural gas are also declining and this demand is now being met
with increasingly higher priced supplies.
The U.S. will spend almost $90 billion in 1980 for foreign oil. This
high import level also reduces jobs and our ability to maintain our eco-
nomic and national security. A recent study (Reference 1) conducted by the
Institute of Gas Technology concluded that the actual benefit to the nation
from reducing oil imports is $75.00 per barrel, even though the current
cost of oil is only $37.00. The former figure takes into account external
benefits, such as the effects on inflation, employment, and national secur-
ity. These are the considerations, along with the uncertainty inherent in
the import supplies, that now provide the impetus for federal support of
synfuel development. Recent federal action creating the Synthetic Fuel
Corporation (SFC) is aimed at alleviating some of the factors that
previously have discouraged development.
2.1.1.3 Nature of Synfuel Industry Development
The development of a synfuel industry will be influenced by certain
characteristics of the exising production and marketing infrastructure for
oil and gas products. Interviews with potential synfuel producers and
users (see Appendix A) indicate that the following considerations are
significant:
18
-------
• The development of the synfuel liquids industry will be dominated
by the oil companies. Those technologies that tend to utilize
existing capital stock (refineries and distribution systems) will
be favored that is, syncrude treated and upgraded for use in
existing refineries.
t Those technologies that produce products that more closely conform
to current consumption patterns and end use devices will be favored
for early development.
t Certain captive markets, for example, chemical feedstocks, may
present a special incentive for certain synfuel development
(medium-Btu gas) to ensure supplies for production processes.
There are several impediments, however, to the establishment of a
viable synfuel industry by the early 1990s. The most important are:
• Capital Requirements. Capital requirements are estimated to range
from $30 to $45 thousand per daily barrel of equivalent oil from
coal. Thus a 100,000 barrel per day facility (equivalent in size
to a medium-sized oil refinery) would cost $3 to $4.5 billion.
This cost is 6 times the cost of an equivalent oil refinery. This
exceeds the financial capabilities of all but a handful of corpora-
tions, and such investments are likely *o re' lire preemption of all
other corporate objectives.
• Return on Investment. Based on current world oil prices, synthetic
fuels could not be produced profitably. Future profitability is
uncertain and depends on escalating plant construction cost, future
world oil prices, and future raw materials costs. For example,
from 1962 to 1978 coal costs in constant dollars have increased
faster than oil costs.
• Infrastructure. The expected synfuel industry build-up will
demand a coordinated expansion of the entire supporting infra-
structure that is necessary for energy product manufacture,
distribution, and use. Water, power and transportation networks
will have to be expanded or, in remote areas, completely con-
structed. Community development and labor force expansion will
require similar effort. All of this will put tredmendous financial
demands on the public and private sectors.
0 Permitting. Permitting has been a lengthy and uncertain activity.
In addition to the permitting procedure's complexity, at times it
is necessary to traverse conflicting unmodified state, local, and
federal regulations. Several energy projects have been aborted
because of permitting complexities. Facilities as large and com-
plex as commercial-scale synthetic fuel plants will require four to
five years to construct. Historically, for many major energy
facilities the severe delays caused by permitting and licensing
19
-------
problems have been longer than the time required for engineering
and construction. Delays in these highly capital intensive
projects could mean large overruns in project costs and interest
penalties. As discussed above, continually changing patterns of
environmental and other regulatory requirements have made potential
investors reluctant to commit large capital resources to unproven
technologies without assurances that regulatory changes will not
adversely affect the economic viability of the plant after the
projects have begun.
• Technology Risks. Although available technology can reduce
engineering and operational risks, such risks are not completely
eliminated. The coal and shale facilities will be first-of-a-kind
plants. Some of them will be based on, or be a combination of,
processes practiced elsewhere, but not in the United States. With
a few notable exceptions, plants with the specific configuration
best suited to the American market have not been built anywhere.
• Uncertainties about Government Action. Industry also perceives a
great deal of uncertainty in how government views synthetic fuels.
There is also hesitancy to be the first to build a large plant.
First plants tend to have bigger cost overruns, face greater tech-
nological risk and design changes, and may have shorter economic
lives than subsequent plants.
Recognizing these impediments, federal action has directed the
creation of the Synthetic Fuels Corporation with a multibillion dollar
budget to encourage the synfuel industry by providing incentives such as
price support for products, loan guarantees, direct loans, and government
ownership of plants.
2.1.2 Synfuel Industry Build-up Scenarios
Three scenarios or projections of synfuel industry build-up rates to
the year 2000 have been developed to illustrate the potential range of
synfuel product utilization:
• A national goal scenario driven by federal incentives
• A nominal, or most likely, production scenario
• An accelerated production scenario representing an upper bound for
industry build-up.
2.1.2.1 National Goals Scenario - Scenario I
The specific national synfuel goals are:
20
-------
• Coal Liquids. To stimulate and accelerate the construction and
operation of the first few plants to provide sufficient data on the
competing commercial coal liquefaction processes so that industry,
with its own investment, stimulated by government incentives, if
required, will build plants with sufficient energy capacity to
provide up to 1 MMBPD of liquid fuels by the year 1992.
• Shale Oil. To stimulate shale oil production at the rate of 0.4
MMBPD by 1990.
t High-Btu Gas. To develop and implement a program that enables the
U.S., by 1992, to produce significant quantities of pipeline
quality gas (0.5 MMBPD oil equivalent) from commercial HBG plants
in an environmentally acceptable manner. This is facilitated by
the short-range goal of having two or three commercial HBG plants
in operation by the mid-1980s.
t Low-/Medium-Btu Gas. To stimulate an initial near-term commercial
capability for several medium-Btu commercial plants for the mul-
tiple applications of low-Btu gas in each of the prime industry
markets. Once a capability has been established, capacity will be
accelerated to achieve at least 0.29 MMBPD oil equivalent by 1992.
Of this total, up to 0.04 MMBPD oil equivalent will be provided
from 40 to 50 low-Btu facilities and up to 0.25 MMBPD oil equiva-
lent from 25 to 30 medium-Btu plants. The medium-Btu gas produc-
tion goal includes the amount that is likely to be used for the
production of methanol--a-state-of-the-art technology step.
The key assumptions underlying achievement of these goals are:
federal funds provided are sufficient to reduce investment risk by the
synfuel industry through 1992; and other requirements for industry
development are satisfied, that is, environmental permits, material,
equipment, and labor. A likely build-up rate profile for the synfuel
industries under this scenario is shown in Figure 1.
Figure 1. Synfuel Industry Cuild-up for the National Goal Scenario
The rationale for the curves in Figure 1 is that after the
construction of a given production capacity based on the best available
technology with federal government incentives, a period of operational
21
-------
experience gathering will follow in which synfuel economics and technical
and environmental performan- '11 be assessed. When this assessment con-
cludes that the investment s worth taking, further commercial plants
will follow. This type of .ry production profile occurred with the
federal support of the syntfr i rubber industry during World War II.
2.1.2.2 Nominal Production Scenario - Scenario II
Recent studies of the technical capability of the U.S. to meet the
synfuel national goal conclude that there are significant concerns
regarding achieving this goal (Ref>/ence 2,3,4,5). These concerns include:
• Availability of Skilled Manpower. It is expected that the supply
of engineers and construction labor will be severely taxed to meet
the synfuel production goal set forth in Scenario I.
• Availability of Critical Equipment. Certain critical equipment
such as compressors, heat exchangers, and pressure vessels are
expected to be in short supply unless corrective measures are taken
now, thus slowing the synfuel industry build-up rate indicated in
Scenario I.
• Diversion of Investment to Competing Technologies. Demand on the
limited capital available in the economy by competing energy supply
technologies, such as coal liquefaction, coal gasification, oil
shale, geothermal, and solar technologies, could result in the
slowing of build-up rates for some technologies.
• Environmental Data. Lack of environmental data needed for
regulatory approvals could slow down the build-up rate.
Furthermore, the response to questions on the subject of synfuel plant
build-up asked in the course of interviews with potential suppliers of syn-
fuels as part of this study (Appendix A), indicates that the total synfuel
market may develop less rapidly than the national plan. The consensus
places total production at 1.0 to 1.5 MMBPD by 1990. According to poten-
tial suppliers, the major factors affecting the build-up rate include the
degree of government support and the effect of environmental attitudes
towards industry, especially regarding the Clean Air Act and water regula-
tions. Potential synfuel suppliers also pointed out that shale oil is
probably more nearly cost competitive and closer to commercialization than
major coal-derived synfuel products. Taking these concerns into
consideration, a nominal synfuel production build-up, Scenario II, was
developed (Figure 2). A production rate of about 2.1 MMBPD is estimated by
the year 2000, instead of 1992 as indicated in Scenario I. The technolo-
gies expected to contribute to both Scenarios I and II are the same. The
major difference is in the rate of build-up: Scenario II is slower.
22
-------
g
YEAR
1984
1986
1988
1990
1992
1994
1996
1998
2000
Figure 2. Synfuel Industry Build-Up for the Nominal Production Scenario
2.1.2.3 Accelerated Production - Scenario III
The accelerated production scenario is based on the assumptions that:
federal incentives are sufficient to meet the national goals in 1992;
operation of synfuel plants up to 1992 is so successful that greater
investment in commercialization plants is justified; all resource equipment
requirements are satisfied; and licensing/permitting procedures are ade-
quately streamlined. In this case, new plant capacity continues to be
added up to the year 2000 at about the same rate as the build-up to 1992.
For shale oil, the production of 0.9 MMBPD by the year 2000 is based on a
survey and analysis of the desired goals of each industrial developer.
indicated in Figure 3, a total synfuel
could be reached by the year 2000. This
liquids, 1.5 MMPBD of gas, and 0.9 MMBPD of
Under these conditions, as
production rate of 5 MMBPD
includes 2.6 MMBPD of coal
shale oil.
Because of the previously discussed limitations facing the synfuels
industry, the accelerated production scenario is highly unlikely, and
Figure 3 probably shows the upper bound to synfuels utilization over the
next 20 years.
2.1.3 Other Synfuel Production Projections
Table 6 includes some recent projections for synfuel production taken
from published periodicals or reports. It shows the originating person or
organization, the projected synfuel production, and the source. The
methods used for these estimates vary, but the most common approach was to
23
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TABLE 6. SYNFUEL PROJECTIONS
Organization
Projection
Source
Eric Reich!, former
President of Conoco
Coal Development
Booz, Allen &
Hamilton
Frost & Sullivan
Exxon
DOE
Institute
nology Assessnent
0.25 MMBPD coal liquids & gas in
1990
Medium-Btu Gas-0.7 MMBPD in
1990
High-Btu Gas -1 KMBPD in
1995
1990
2000
Synfuels 3/14/80
Synfuels 3/14/80
Inside DOE 4/25/80
Synfuels 2/8/80
Coal
liquids 1-1.5 MMBPD 9.5 Mf«PD
Coal
gas
Coal
gas
Coal &
Shale
1 iquids
Coal
1 iquids
Coal gas
Shale
0.8 MMBPD
1990
0.5 MMBPD
0.7-1 MMBPD
2000
0.7-1.8
0.8-1
0.9-1.3
2.2 MMBPD
2000
C.7-1.5 '-"-'BPO
3.3-4.6 MMBPD
MMBPD
MMBPD
MMBPD
Energy Outlook
1980-2000,
Exxon Company
Publication,
Dec. 1979
National Energy
Plan II
May 1979
2000
All Synfuels 2.1
0^1 Shale 0.4 T3PD
Bankers Trust Co.
1990
All Synfuels 0.5 MMBPD
Synfuels 8/22/80
An Assessment of
Oil Shale Tech-
nology, June 1,
1980
0~A publication
Synfuels 8/15/80
24
-------
ItM
Itll
itto
Figure 3. Synfuel Industry Build-Up for the Accelerated
Production Scenario
estimate total
estimate total
synfuels.
gas and/or liquids supplies, both donestic and imported;
demand; and assume any differences would be supplied by
As can be seen from the table, there exists a wide variance in synfuel
production projections. The projections shown range from 0.25 WBPD of
coal-derived synfuels in 1990 to almost 2.3 MMBPD in 1990 and 11.7 MMBPS in
2000. Projections for shale oil production generally range fron 0.5 MMBPD
to 3 or 4 MMBPD by 2000. The production rates estimated for Scenarios I,
II, and III fall well within the ranges of these projections.
2.2 SYNFUEL PLANT AND PRODUCT BUILD-UP SCENARIOS
The previous sections presented three scenarios for the development of
the synfuel industry to the year 2000. These scenarios project, Py
year, the total quantity of shale oil, liquids from coal, and gases fron
coal that will enter the market. There are many synfuel processes: each
has a characteristic product slate, and each product may have a character-
istic environmental impact as it enters the transportation- utilization
network. Thus, the next step of this analysis of the environmental aspects
of synthetic fuels utilization was to consider the major competing synfuel
processes and, based on current industry plans and the technical maturity
of each process, break down the total production into production by
specific process technologies.
25
-------
2.2.1 Shale Oil
2.2.1.1 Shale Oil Build-Up Rates
The oil shale industry appears to be the most advanced of all synfuel
industries in the United States. There are several majors (consortiums and
companies) with established projects and plans (Table 2). The techno-
logies, which are proprietary, appear to be sufficiently mature to move
ahead to oil shale commercialization. The commercialization of the indus-
try is, however, predicated on several of the factors discussed previously
(most notably world oil prices and availability of risk-reducing
incentives) and some specific issues:
t Land problems such as land exchanges, leases, unpatented mining
claims, and the availability of off-tract disposal sites. More
than 80 percent of the oil shale land is owned by the federal
government.
• Resolution of environmental issues. Certain majors already have a
final EIS enabling them to proceed to commercialization. Colony
has a final EIS for a nominal 50,000 BPD complex and Union has an
EIS for a 10,000 BPD commercial module demonstration. Other majors
will have to obtain permits before they can proceed with commercial
operations.
• Availability of skilled labor (e.g., hard rock miners) that is
currently in short supply.
• Maturity of technologies (surface retorting technologies are more
advanced than modified in-situ technologies).
• Distance of resource location from likely end user regions and the
feasibility of upgrading the existing oil transportation system at
a reasonable cost.
The development of the oil shale industry as it might proceed under
each of the three scenarios is projected based on considerations for each
specific project and process.
Tables 7 through 9 summarize the development of the oil shale industry
for each of the three scenarios. Both the national goals and nominal pro-
duction scenarios reach a production rate of 440,000 BPD by the year 2000,
but the nominal case builds up more slowly. The accelerated production
scenario reaches 930,000 BPD.
The plant build-up rate levels off in the later years based on the
assumption that production will remain at the maximum level of a commercial
plant with no new capacity coming on-stream before 1990. Where production
has not yet reached full plant capacity, it was increased incrementally to
accommodate this. It is felt that first-of-a-kind new technologies will be
brought on-stream in a careful, calculated, and conservative manner, with
26
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TABLE 7. OIL SHALE PLANT BUILD-UP, SCENARIO I
U.S. OIL SHALE PRODUCTION - THOUSAND BPD
ro
Projected
Plant/Process
Exxon 011 Corporat1on/(A)
Occidental 011 Shale/(B),
Lease Tract C-b (PON)
Geoklnetlcs, lnc./(C),
Unlta Basin (PON)
Superior 011 (Mu1t1m1neral)/(D),
Plceance Basin
Tosco Sand Wash/(E),
Ulnta Basin
Union 011/(F),
Long Ridge, Plceance Basin
White River Project/(G),
Lease Tracts Ua.Ub, Ulnta Basin
Project Rio Blanco/(H),
Lease Tract C-a (PON)
Colony/Tosco/ (E),
Parachute Creek, Plceance Basin
Total
1980 1981 1982 1983 1984 1985 1986
5
2 4 10 12
13 13 13
9 9 9 40 80
444
4 4 4 14
9 9 9 36
•9 24 «1 80 164
1987
10
14
13
90
16
29
47
219
1988
30
20
16
13
21
90
33
43
47
313
1989
30
30
18
13
30
90
50
58
47
366
1990
37
40
20
13
43
90
50
60
47
400
Estimated
1991
60
50
20
13
47
90
50
60
47
437
1992
60
50
20
13
47
90
50
60
47
437
1993
60
50
20
13
47
90
50
60
47
437
1994
60
50
20
13
47
90
50
60
47
437
1995
60
50
20
13
47
90
50
60
47
437
1996
60
50
20
13
47
90
50
60
47
437
1997
60
50
20
13
47
90
50
60
47
437
1998
60
50
20
13
47
90
50
60
47
417
1999
60
50
20
13
47
90
50
60
47
437
2000
60
50
20
13
47
90
50
60
47
417
•Source: USOOE: 011 Shale Industrialization Action Plan, Feb. 1980
Process:
A - Unknown
B - Vertical modified 1n situ (MIS)
C - Small, horizontal, 1n situ retort clusters
0 - Surface retort, traveling grate
E - Tosco II
F - Union B
G - Surface retort, Paraho direct and Indirect modes
H - Lural, surface retort
-------
TABLE 8. OIL SHALE PLANT BUILD-UP, SCENARIO II
U.S. SHALE OIL PRODUCTION - THOUSAND RPfl
ESTIMATED
Company
Chevron Oil
Plceance Basin
Mobil Oil
Plceance Basin
Occidental 011 Shale
Lease Tract C-b
Plceance Basin
Geoklnetlcs, Inc.
Ulnta Basin
Tosco Sand Mash
Ulnta Basin
Getty
Plceance Basin
ro
00 Union 011
Long Ridge, Plceance Basin
White River Project
Lease Tracts Ua.Ub, Ulnta Basin
Project Rio Blanco
Lease Tract C-a
Plceance Basin
Colony
Parachute Creek, Plceance Basin
TOTAL
19B3 1984 1985 1986 1987 1988 1989 1990
25 40 50
4 10 10 10
15
3 5 10 10
25 40 50 50
5 10 10 10
,99 9 25 40 50
25
25 40 50
25 40 50 50 50
99 9 25 77 190 250 315
1991
50
25
25
20
50
10
50
40
50
50
370
1992
50
40
40
20
50
10
50
50
50
50
410
1993
50
50
50
20
50
10
50
50
50
50
430
1994
50
50
50
20
50
10
50
50
50
50
430
1995
50
50
50
20
50
10
50
50
50
50
430
1996
50
50
50
20
50
10
50
50
50
50
430
1997
50
50
50
20
50
10
50
50
50
50
430
1998
c~.
to
50
20
50
10
50
50
50
50
430
199*
50
50
bO
20
5C
10
50
50
50
50
430
2000
50
50
:o
20
50
10
50
50
50
50
430
-------
TABLE 9. OIL SHALE PLANT BUILD-UP, SCENARIO III
U.S. OIL SHALE PRODUCTION - THOUSAND BPD
Plant/Process
Chevron 011 (A),
Plceance Basin
Mobil 011 /(A),
Plceance Basin
Occidental Oil Shale/(B),
Lease Tract C-b (PON)
Geoklnetlcs, Inc./(C)
Uinta Basin (PON)
Superior Oil (Multlmlneral)
V(D) Plceance Basin
Tosco Sand Wash/(E),
Uinta Basin
Union 011/(F)
Long Ridge, Plceance Basin
White River Project/(G)
Lease Tracts Ua. Ub, Uinta Basin
Project Rio B1anco/(B),
Least Tract C-a (PON)
Colony/Tosco/(E),
Parachute Creek, Plceance Basin
Naval Oil Shale Reserve/ (H),
Plceance Basin
Demonstration of above
Ground Retorting (DOE-PON)X(A)
Demonstration of Advanced
Retort Technology (DOE-PON)X(A)
Carter 01 1/ (A)
TOTAL
Projected
1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990
5 10 20 30 40 50 75 100
6 6 30.6 42.5 50
6.3 30 50 50 87.5 140 200
5 5 10 15 25 40 50 50 50
6.7 10 12 12 12 12
25.9 38.4
8.6 8.6 8.6 27 45 45 45 45 45
19 45.6 76 76 76 76 76
25.9 38.4 46.2 46.2 46.2 46.2 46.2
28
8 4
8
16.8 24.9 30 45 60
13.6 26.6 83.8 102.7 305 340.1 427.3 557.6 713.6
1991
100
50
200
50
12
46.2
45
76
46.2
41.5
8
60
734.9
1992
100
50
200
50
12
46.2
45
90.8
46.2
50
60
750.2
1993 1994 1995 1996
100 100 100 100
50 78 91.5 100
200 200 200 200
50 50 50 50
12 12 12 12
46.2 46.2 46.2 46.2
45 45 45 45
45 90 90 90
111.6 135 135 135
46.2 46.2 46.2 46.2
50 50 50 50
60 60 60 60
816.0 912.4 925.9 934.4
Estimated
1997 1998 1999 2000
100 100 100 100
100 100 100 100
200 200 200 200
50 50 CO 50
12 12 12 12
46.2 46.2 46.2 46.2
45 45 45 45
90 90 90 90
135 135 135 135
46.2 46.2 46.2 46.2
50 50 50 50
60 60 60 60
934.4 934.4 934.4 934.4
*Source: Denver Research Institute, University of Denver, Oct. 1979
Process: A - Unknown
B - VMIS, surface retort
C - Small, horizontal, 1n situ retort clusters
0 - Surface, circular grate
E - Tosco II
F - Union B
G - Paraho retort, direct and Indirect modes
H - Process not selected
-------
maximum production being equal to one commercial plant size. Where pro-
jections (e.g., Chevron, Mobil, Occidental in Scenario III; and Union in
Scenario I) already show several commercial plants, no attempt has been
made to decrease these plant outputs.
The National Goals Scenario
For Scenario I, the development of individual shale oil projects is
given according to the United States Department of Energy Oil Shale
Industrialization Action Plan, February 1980. Table 7 presents the devel-
opment schedule as taken from the DOE Action Plan. This scenario is based
on interviews with persons in private industry, and considers only those
projects at a relatively advanced stage of development.
The Nominal Production Scenario
For Scenario II, the nominal production scenario, the likely
development of major oil shale projects is presented to the year 2000.
Taking into account the current status of the major oil shale projects, and
incorporating the length of time required to go from the current project
status to full commercial production, the likely development of the oil
shale industry is estimated. Two years are allowed for preparation and
approval of an environmental impact statement (EIS), and the current
permitting status of several oil shale projects is indicated in Table 10.
TABLE 10. CURRENT PERMITTING STATUS OF OIL SHALE PROJECTS
Project Status
Occidental Conditional PSD*
Colony Final EIS and conditional PSD
Superior Final EIS, land exchange
reversal pending
Paraho Draft EIS
*Prevention of significant deterioration
In addition, the technical problems peculiar to the process technology
(e.g., pilot plant status, scale-up requirements), the probable delays
caused by land problems or difficulties in negotiating licensing agree-
ments, and the need for a construction and shake-down period of about four
years are taken into account. All of these factors were compiled together
to produce the production schedule given in Table 8.
The Accelerated Production Scenario
For Scenario III, the accelerated production scenario, the development
of individual oil shale projects is based on a Denver Research Institute
survey of the desired goals of industry. Table 9 presents the quantity of
shale oil flowing from each project for each year to the year 2000.
30
-------
Because of the many impediments faced by industry and the short period of
time left to resolve the critical issues causing these impediments, the
probability that this accelerated scenario will be realized is considered
to be low. The way that each project might achieve its goal is outlined in
the following paragraphs.
Chevron Project. The Chevron project will use a surface retorting
technology, and it is assumed it will be scaled up over a six-year period
to 50,000 BPD. A three-dollar-per-barrel tax credit, an investment tax
credit, or accelerated depreciation will be necessary to motivate this
project, and it is assumed these incentives become available in 1980.
Engineering, design, and construction are completed in 1983 for a first
module. The plant is expanded and full production of 50,000 BPD is
achieved in 1988. Due to the success of the first module, a decision is
made in 1987 to double the projected capacity, and the second commercial
plant comes on-stream in 1990 for a total capacity of 100,000 BPD.
Mobil Project. It is assumed that incentives are provided in 1982,
and over a four-year period a 6,000-BPD module is developed. Two years
after successful operation of the module, commercial operation begins on a
56 percent, 83 percent, 100 percent startup profile. Commercial capacity
of 50,000 BPD is reached in 1990 and capacity is doubled in 1996.
Occidental Project. Given successful technical results from the Logan
Wash pilot operation and the C-b tract work, the Occidental modified in
situ (MIS) project is assumed to follow two phases: Phase I producing
50,000 BPD by 1986; and Phase II producing 200,000 BPD by 1990. Of the
200,000 BPD capacity, 62 percent will be MIS and 38 percent will be surface
retorting. Phase I begins in 1984 and is scaled up from two retorts to
ten retorts over a three-year period. Phase II goes into start-up in 1988
on a 25 percent, 60 percent, 100 percent start-up profile, full capacity
being achieved in 1990.
Carter Oil Project (Exxon). This project will require a three-dollar-
per-barrel tax credit land exchange and a ten-percent investment tax
credit. It is assumed that these incentives are provided by 1982 and that
Carter Oil initiates development as soon as the incentives are available.
The plant is expected to be expanded from an initial 16,000 BPD in 1986 to
60,000 BPD in 1990 by successive modular additions.
Geokinetics Project. The Geokinetics project will consist of a set of
small, horizontal in situ retort clusters, each with a maximum capacity of
5,000 BPD. The following schedule of development is assumed:
31
-------
Year Location Name
1982 Section 2, T145, R224 Hollandberg
1984 Section 23, T125, R20E Agency Draw #1
1985 Section 13, T135, R20E Agency Draw #2
1986 Section 36, T125, R22E Buck Canyon
1986 Section 16, T135, R22E Sunday School
1987 Section 10, T135, R22E Wood Canyon
1987 Section 36, T135, R23E McCook Ridge
1987 Section 16, T135, R24E Brewer Canyon
1988 Section 2, T135, R24E Wolf Den #1
1988 Section 36, T125, R24E Wolf Den #2
White River Project. Prior to beginning this project, the developers
must win favorable rulings on land ownerships and unpatented mining claims.
We assumed the legal rulings are favorable but not completed until the late
1980's. This paves the way to construction in 1990, start-up in 1993, and
production of 90,000 BPD in 1994.
Rio Blanco Project. It is assumed that the economic climate is
favorable and that the 1980-81 pilot burns are successful. Construction
begins immediately after the pilot production begins in 1984 on a 25
percent, 60 percent, 100 percent start-up profile; and a full commercial
production of 76,000 BPD is achieved in 1986. A second phase of construc-
tion begins in 1989 after the initial phase has been evaluated. The same
start-up profile applies for the second phase, and a production capacity of
135,000 BPD is achieved in 1994.
Superior Oil Project. The Superior Oil Project depends on a federal
land exchange before development can begin. We assumed the necessary lands
are acquired, and construction begins in 1981 leading to production in
1985. After 1985, a start-up profile of 56%, 83%, 100% is assumed leading
to a full capacity of 12,000 BPD in 1987.
Colony/TOSCO Project. We assumed the risks due to environmental
regulations and third party suits have been minimized, and financial incen-
tives have been supplied by the government by 1981. Construction commences
in 1981, and production begins in 1984 on a 56%, 83%, 100% start up profile
reaching a total capacity of 46,200 BPD in 1986.
TOSCO Sand Wash Project. This project follows the same schedule and
constraints as the Colony/Tosco project; however, the production schedule
is delayed five years as the Colony/Tosco project is evaluated. Production
begins in 1989 and reaches its full level in 1991 of 46,200 BPD.
Union Oil Project. We assumed the three dollars per barrel tax credit
is passed in 1980 providing adequate incentives for construction to begin
immediately. The 10,000 ton/day demonstration plant is assumed to be
successful and comes on-stream in 1982 producing 8,6000 BPD. Owing to the
32
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success of the demonstration plant, capaciity is extended to achieve 30,000
BPD by 1986 using 7 retorts each averaging 10,000 tons per day of thirty
gallon per ton (avg.) oil shale
Naval Oil Shale Project. Feasibility studies will be used to
determine the specific process technologies used to achieve a goal of
50,000 BPD in 1992. A 56 percent, 83 percent, 100 percent start-up profile
is assumed to begin in 1990.
Department of Energy Demonstration of Above-Ground Retorting Project.
The schedule given in Table 9 is taken from DOE management objectives.
Department of Energy Demonstration of Advanced Retort Project. The
schedule given in Table 9 is derived from a private communication with
DOE-LETC.
2.2.1.2 Shale Oil Product Build-up Rates
The product and by-product build-up rates for the three scenarios are
presented in Figures 4, 5, and 6. These product rates correspond to the
projected plant build-up rates and processes identified for each plant.
In some cases, such as for Exxon and Chevron where no choice of process has
been announced, a shale oil recovery process was arbitrarily assigned.
If, when that company begins actual operation, a different process is
chosen, the impact on the shale oil industry totals should not be signifi-
cant. The upgrading process used was either hydrotreating or coking; the
particular process applied to each crude shale oil can be determined by the
presence or absence of coke.
Three major refining processes were considered coking, fluid
catalytic cracking, and hydrocracking (Reference 6). Hydrocracking was
chosen for two reasons. First, its yield and range of products were the
most desirable. Second, many industry publications, such as the Oi1 and
Gas Journal, report that the use of hydrocracking will grow significantly
during the remainder of this century. Typical yields from hydrocracking
(Reference 7) are:
Product Percent Yield
LPG 0
Gasoline 17
Jet fuel 20
Diesel fuel 54
Residues 9
Taking the total production of shale oil as given in Tables 7, 8, and
9, and multiplying the total production by the fraction of each product
produced by hydrocracking yields the total flow rates of the final products
33
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from oil shale processing and refining. Classifying jet fuel and diesel
fuel as middle distillates, the product flow rates indicated in Figures 4,
5, and 6 are obtained.
The major markets expected
transportation fuel market
It is anticipated that the
petroleum fuel.
to be served are the middle-distillate
(jet and diesel fuels) and the gasoline market.
refined products will be indistinguishable from
o
0.
CD
z
o.a
0.7
0.6
0.5
0.4
0.3
0.2
0.1
1980
Gasoline
• -Idle Distillates
Residues
1984
1988 1992
YEAR
1996
2000
Figure 4. Oil Shale Product Build-Up For Scenario I
34
-------
£
o
z
1.0
0.9
0.6
0.7
0.6
0.5
0.4
0.3
0.2
0.1
Gasoline
^.^SRi=~T}5£rir= T5S Middle Distillates
Residues
1980
1984
1988 1992
YEAR
1996
2000
Figure 5. Oil Shale Product Build-Up For Scenario II
CD
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
Gasoline
s Middle Distillates
Residues
1980
1984
1988 1992
YEAR
1996
2000
Figure 6. Oil Shale Product Build-Up for Scenario III
35
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2.2.2 Coal Liquefaction and Gasification
The likely contributions of the specific coal liquefaction and
gasification processes are considered in this section, in accordance with
the overall levels of production given in Scenarios I, II, and III. Coal
liquefaction is divided into direct and indirect liquefaction; coal gasi-
fication is divided into high- and medium-/low-Btu gasification. The
specific processes considered are listed in Table 11.
TABLE 11. PROCESS TECHNOLOGIES UNDER CONSIDERATION
Direct
Liquefaction
Indirect
Liquefaction
High-Btu
Gasification
Med-/Low-Btu
Gasification
SRC
H-Coal
Fischer-Tropsch
Mobil -M
Lurgi
Slagging-Lurgi
Lurgi
Texaco Partial
Oxidation
EDS Advanced
Indirect
Advanced
Fluidized Bed
Advanced
Direct
These processes were selected based on technical maturity (Reference
8, 9) and suitability to the end use application. Process technologies not
included may play a significant role; however, they produce similar
products and will not differ noticeably in their environmental impact.
Additional comment is warranted concerning SRC. There are two major
SRC processes earmarked for commercialization: SRC I and SRC II.
Traditionally, SRC I produces primarily a solid product, whereas SRC II
produces primarily a liquid product. Recently, however, techniques for
modifying the SRC I process to produce liquids have been demonstrated at
the bench scale (Reference 10). Because the relative viability of the two
processes has yet to be determined, and because the final product slates
may vary considerably, SRC I and SRC II are both classified together as
SRC.
As direct liquefaction technology matures, promising developments
(such as short contact time liquefaction) now occurring at the bench scale
could develop into commercial processes in the next decade. These pro-
cesses are likely to have greater yields of gasoline and middle distillate.
To make a realistic appraisal of the environmental impact of the utiliza-
tion of coal liquids, changes in technology over time are considered.
Because the precise process that will dominate in the future cannot be
predicted, the generic term, advanced direct liquefaction, is used.
Similarly, a number of indirect liquefaction processes being developed at
the bench scale have shown significant improvements over the conventional
Fischer-Tropsch and Mobil-M processes in terms of product yield and qual-
ity. These processes could be very important in the 1990's and, therefore,
36
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are considered under the generic name advanced indirect liquefaction.
Advanced fluidized bed gasification refers to any circulating, agglomer-
ating, fluidized bed gasifier such as Westinghouse or U-Gas.
2.2.2.1 Coal Liquefaction Plant Build-up Rates
The coal liquefaction plant build-up rates for the three scenarios
described in Section 2.2.2 are presented in Tables 12 through 14. These
three tables give the cumulative number of 50,000 BPD coal liquefaction
plants on-stream for the three time periods 1980-1987, 1988-1992, and
1993-2000. For Scenario I, the national goals scenario, the goal of 1MMBPD
of coal liquids by 1992 is met predominately by indirect coal liquefaction
(80 percent). Scenario III, accelerated production, builds up at the same
rate as Scenario I to 1992, and continues to build up at that rate so that
by the year 2000, 2.6 MMBPD is produced. For Scenario I, no new capacity
beyond 1992 is projected. For Scenario II, the nominal case, no plants are
projected to be on-stream until 1992, with a growth rate beyond that year
yielding about 1.0 MMBPD in the year 2000. The rationale supporting pro-
jections of specific plant and product build-up rates is outlined in the
following paragraphs for each of the three time frames.
1980-1987
The technological status of coal liquefaction during this time can be
characterized by the following observations:
• At present, the only commercially demonstrated coal liquefaction
process is the Fischer-Tropsch process used in the SASOL plant in
TABLE 12. COAL LIQUEFACTION PLANT BUILD-UP FOR SCENARIO I
Process
Indirect Liquefaction
Fischer-Tropsch
Mobil M
Advanced Indirect
Direct Liquefaction
SRC
H-Coal
EOS
Advanced Direct
Total Indirect Liquefaction
Total Direct Liquefaction
Total Liquefaction
Number of Plants on
80 - 87 88 - 92
3 7
3 8
1
1
1
1
1
6 16
4
6 20
Stream
93 - 2000
7
8
1
1
1
1
1
16
4
20
Note: Numbers indicate cumulative number of 50,000 BPD plants during
different time periods.
37
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TABLE 13. COAL LIQUEFACTION PLANT BUILD-UP FOR SCENARIO II
Process
Indirect Liquefaction
Fischer-Tropsch
Mobil M
Advanced Indirect
Direct Liquefaction*
Total Indirect Liquefaction
Total Direct Liquefaction
Total Liquefaction
Number of Plants on
80 - 87 88 - 92
1
1
1
2
1
3
Stream
93 - 2000
2
2
9
7
13
7
20
*Process not specified.
Note: Numbers indicate cumulative number to 50,000 BPD plants during
different time periods.
TABLE 14. COAL LIQUEFACTION PLANT BUILD-UP FOR SCENARIO III
Process
Indirect Liquefaction
Fischer-Tropsch
Mobil M
Advanced Indirect
Direct Liquefaction
SRC
H-Coal
EDS
Advanced Direct
Total Indirect Liquefaction
Total Direct Liquefaction
Total Liquefaction
Number of Plants on
80 - 87 88 - 92
3 7
3 8
1
1
1
1
1
6 16
4
6 20
Stream
93 - 2000
7
8
17
2
2
2
14
32
20
52
Note: Numbers indicate cumulative number of 50,000 BPD plants during
different time periods.
38
-------
South Africa. This process, which is an example of indirect lique-
faction, has been commercially operated since 1956. Currently a
new plant incorporating process improvements is in start-up as an
expansion program (Reference 11).
t A second indirect liquefaction process, the Mobil-M process, should
be commercially demonstrated within this time period (Reference
12). A pilot scale demonstration in Germany is scheduled for 1983,
and a commercial plant operating on reformed natural gas is
scheduled for operation in New Zealand by 1984.
• At present, there are no commercially demonstrated direct coal
liquefaction processes (Reference 8). Exxon Donor Solvent (EDS)
and H-Coal pilot plants are scheduled to start operation and
assessment of operating data from these plants should be sufficient
to determine their commercial readiness and competitive position
relative to indirect liquefaction by 1984. In addition, the SRC
demonstration plants should be operating by 1984, providing an
initial assessment of commercial readiness.
To meet the production schedules suggested by Scenarios I and III,
industry, with the federal incentives, must initiate the design and
construction of about six coal liquefaction plants early in the 1980-1987
time period and ten additional coal liquefaction plants in the 1980-1987
time period, each plant having a nominal production rate of 50,000 BPD of
oil equivalent. The plants must be initiated well in advance of the target
date for commercial production because four to five years are required to
design, construct, and start up a commercial scale coal liquefaction plant
(Reference 13).
Appendix B summarizes the coal liquefaction projects currently being
planned or commercially operated by industry. Nine commercial coal lique-
faction projects have been identified, and are listed on page B-2. All of
these projects use indirect liquefaction processes to produce either metha-
nol or hydrocarbons, with the hydrocarbon processes consisting exclusively
of the Fischer-Tropsch technology as embodied in the SASOL plants.
Appendix C summarizes the solicitation awards for feasibility studies and
cooperative agreements issued recently by the U.S. Department of Energy to
promote synfuel projects. These appendices demonstrate that industry and
government favor indirect liquefaction over direct liquefaction and that
they are confident of the commercial viability of the SASOL technology in
the United States.
SASOL has a broad product distribution, whereas Mobil-M produces
primarily gasoline, a highly marketable product. However, SASOL has been
commercially demonstrated in South Africa, but Mobil-M may not be commer-
cial until after 1984. On balance, it appears at this time that there are
equal incentives to develop and build both SASOL and Mobil-M plants, and
that their development rates are likely to be the same. Three plants of
each type are projected to come on stream during this time frame.
39
-------
Direct liquefaction is more thermally efficient than indirect
liquefaction (Reference 14); therefore, direct liquefaction is likely to
play a major role after the successful operation of the demonstration
plants. Because direct liquefaction technologies are less advanced tech-
nically, there is likely to be no decision to commercialize direct coal
liquefaction until the end of the 1980-1987 period. These plants will
probably not come on-stream until the 1988-1992 time period, because four
to five years will be required to construct them and make them operational \
Accordingly, no direct liquefaction plants are projected to come on-strear
in the 1980-87 period.
In contrast to Scenarios I and III, the nominal Scenario II does not
project any coal liquefaction plant coming on-stream in the 1980-1987 time
period. Towards the end of the 1980-1987 time period, it is likely that
plans and construction will begin for plants to come on stream in the
1988-1992 period.
1988-1992
The technological status of coal liquefaction in this period is
characterized by the following observations:
t Depending on the intensity of commercialization efforts initiated
in the 1980-1987 period, varying numbers of indirect coal lique-
faction plants embodying both Fischer-Tropsch and Mobil-M
technology will come on-stream.
• It is expected that the EDS and H-Coal pilot plants are operating,
and the SRC demonstration plants are providing information requirec
for commercial scale-up (Reference 15). In addition, certain
advanced concepts (e.g., short contact time liquefaction and Kolbe1
technology (Reference 16) are likely to be incorporated into the
commercial process technologies.
For Scenario I, no new construction will be initiated in this period.
For Scenario III, however, a vigorous program of construction will
continue. A total of 32 liquefaction plants will come on-stream in the
1993-2000 time frame; this will require the planning of four new plants
each year, starting in 1988. The commercial testing of direct liquefaction
is likely to be successful and the decision will be made to initiate the
construction of four direct liquefaction plants, probably one each for SRC,
EDS, H-Coal, and an advanced direct liquefaction process. Also, because of
their attractive product distributions deriving from the development of
improved catalysts, advanced indirect liquefaction processes will probably
remain competitive with direct liquefaction. The remainder of the plants
initiated during this time period under Scenario III will likely be
indirect liquefaction plants, probably advanced indirect liquefaction.
As indicated previously for the 1980-1987 time frame, Scenario II
predicts a significantly less intensive commercial effort than Scenarios I
and III. As mentioned in Section 2.1, there are technical and socio-
40
-------
economic constraints on the development of coal liquefaction. These
constraints will probably remain until the late 1990's. For Scenario II,
then, it is estimated that a coal liquefaction commercialization program
will not be launched until about 1987, at which time a decision will be
made to initiate approximately three projects per year, one of direct
liquefaction and two of indirect liquefaction. The direct liquefaction
processes will probably initially involve the same technology used in 1984,
but by about 1990, advanced direct liquefaction should reach commercial
readiness and begin to be incorporated into direct liquefaction commercial
plants.
Indirect liquefaction plants will initially incorporate SASOL-type
Fischer-Tropsch and Mobil-M technologies. Although the pioneer Mobil-M
plant initiated in 1984 incorporated fixed-bed Mobil-M technology with a
Lurgi gasifier providing the synthesis gas feed, by 1988 the fluid bed
technology and Texaco partial oxidation (Reference 8) will likely be
commercially ready and incorporated into all future Mobil-M plants. Also
by 1990, advanced indirect liquefaction will replace SASOL-type Fischer-
Tropsch technology.
1993-2000
For Scenario I, there will be no further build-up of production
capacity for the same reasons outlined for shale oil production in the same
time frame. On the other hand, Scenario III assumes a continued build-up
of production capacity at the rate of about four 50,000 BPD plants per
year, reaching a production capacity of 2.6 MMBPD in 2000. The technology
used in these plants will probably be evenly split between advanced
indirect liquefaction and advanced direct liquefaction.
For the nominal case, Scenario II, production capacity is expected to
increase at a rate of about three 50,000 BPD plants per year to the end of
the decade and reach an ultimate level of 1.0 MMBPD by the year 2000.
During this period, a total of two Mobil-M plants and two Fischer-Tropsch
plants will be built, whereas advanced indirect liquefaction plants will
be introduced at a rate of about one per year before leveling off at the
end of the decade.
2.2.2.2 Coal Gasification Plant Build-up Rates
The coal gasification plant build-up rates for the three scenarios are
presented in Tables 15 through 17. These three tables give the cumulative
number of 42,000 BPD (250 MMSCFD) high-Btu gasification plants and 30,000
BPD medium-/low-Btu gasification plants on-stream for the three time
periods 1980-1987, 1988-1992, and 1993-2000. For Scenario I, 0.6 MMBPD of
coal-derived gasification product is produced by 1992. Scenario III builds
up at the same rate as Scenario I to year 1992, and continues at that rate
so that by the year 2000, 1.5 MMBPD of coal-derived gas is produced. For
Scenario II, the 1992 production rate is expected to be only 0.7 MMBPD,
41
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TABLE 15. COAL GASIFICATION PLANT BUILD-UP FOR SCENARIO I
Process
High-Btu Gas
Lurgi Fixed-Bed
Advanced Fluid Bed*
Low-/Medium-Btu Gas
Lurgi Fixed-Bed
Texaco Partial Oxidation
Total High-Btu Gas
Total Low-/Medium-Btu Gas
Number
80 - 87
7
5
1
7
6
of Plants on
88 - 92
11
1
7
3
12
10
Stream
93 - 2000
11
1
7
3
12
10
*Example: U-Gas or Westinghouse
Note: Cumulative number fo 42,000 BPD high-Btu plants and 30,000 BPD
medium-/low-Btu plants.
TABLE 16. COAL GASIFICATION PLANT BUILD-UP FOR SCENARIO II
Process
High-Btu Gas
Lurgi -Fixed Bed
Slagging Lurgi
Medium-Btu Gas
Lurgi Fixed-Bed
Texaco Partial Oxidation
Total High-Btu Gas
Total Medium-Btu Gas
Number
80 - 87
1
2
1
1
4
of Plants on
88 - 02
4
6
3
4
9
Stream
93 - 2000
4
2
9
6
6
15
Note: Cumulative number of 42,000 BPD high-Btu plants and 30,000 BPD
medium-/low-Btu plants.
42
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TABLE 17. COAL GASIFICATION PLANT BUILD-UP FOR SCENARIO III
Process
High-Btu Gas
Lurgi Fixed-Bed
Advanced Fluid-Bed*
Low-/Medium-Btu Gas
Lurgi Fixed-Bed
Texaco Partial Oxidation
Total High-Btu Gas
Total Low-/Medium-Btu Gas
Number
80 - 88
7
5
1
7
6
of Plants
88 - 92
11
1
7
3
12
10
on Stream
93 - 2000
16
8
11
7
24
18
*Example: U-Gas or Westinghouse
Note: Cumulative number of 42,000-BPD high-Btu plants and 30,000-BPD
medium-/low-Btu plants.
with the growth rate beyond that year yielding about 1.0 MMBPD in 2000.
The rationale supporting these projections is outlined in the following
paragraphs.
1980-1987
The Lurgi fixed-bed gasifier is the leading state-of-the-art high-Btu
gasifier (Reference 17); consequently, it will probably be used in all
high-Btu gasification plants built in this period. For medium-/low-Btu
gasification, the Lurgi gasifier is also currently the leading technology,
but it is likely the Texaco partial oxidation process will also play a
major role. There has been strong industrial and government interest in
the Texaco gasifier (Appendices B and C). The product gas has a very low
methane content (desirable for the chemical industry); the Texaco gasifier
will run on the caking coals characteristic of the eastern U.S.; a demon-
stration plant is likely by 1983. Therefore, it is likely there will be at
least one commercial Texaco gasifier operating by the end of this period.
The production from the high-Btu gas plants would be used solely as a
substitute for natural gas, while the medium-Btu gas would be used for
43
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industrial heat and chemical feedstocks. In all of the scenarios, there
will be no production of low-Btu gas for commerce. Any low-Btu gas would
be used as fuel gas or used on site for combined cycle power generation.
For Scenarios I and III, seven high-Btu gasification plants equipped
with Lurgi gasifiers will come on-stream during this period. For medium-/ ]
low-Btu gasification, Lurgi will be the preferred gasifier because of the
advanced state of its technology. The Texaco gasifier will also likely
play an important role because of current industry interest. One Texaco
medium-/low-Btu plant and five Lurgi medium-/low-Btu gas plants are likel)
to come on-stream during this period for these two scenarios.
For Scenario II, there will be one Lurgi high-Btu gasification plant
coming on-stream (the Great Plains project). Three Lurgi plants and one
Texaco plant will produce medium-/low-Btu gas during this period.
1988-1992
In Scenarios I and III, it is likely that the slagging Lurgi process
(Reference 18) will be demonstrated to be technically viable and it is als:
likely that the slagging Lurgi process will be more efficient and
economical than the conventional fixed-bed Lurgi gasifier. Thus, all new
fixed-bed plants initiated in this period will use the slagging technology.
Late in this period it is likely that advanced fluid-bed gasification will
achieve commercial readiness and four plants using this technology will be
initiated.
For Scenario III, additional plants planned for beyond 1992 will use
slagging Lurgi fixed-bed gasification, advanced fluid-bed gasification, anc
Texaco gasification. No new plants will be planned after 1992 under
Scenario I.
According to Scenario II, there will be four Lurgi high-Btu
gasification plants coming on-stream. In this scenario, the demand for
medium-Btu gas is high, encouraging investment in the Texaco gasifier.
Six Lurgi plants and three Texaco plants are likely to produce medium-/
low-Btu gas during this period.
1992-2000
Within this period, plans will continue for increased gasification
capacity under Scenario III at the rate of three high-Btu gas plants and
two medium-Btu gas plants every two years. Plans will be initiated for an
additional four advanced fluid-bed gasifiers, and by the year 2000 a total
of eight advanced fluid-bed gasifiers will be producing high-Btu gas; the
remaining high-Btu gasifiers will be slagging Lurgi.
For Scenario II, two high-Btu plants using the slagging Lurgi
technology are likely to be initiated in 1988-1992 and will come on-stream
44
-------
after 1992. For medium-/low-Btu gas, three additional conventional Lurgi
fixed-bed gasifiers will come on-stream and three Texaco partial oxidation
plants will come on-stream.
2.2.2.3 Coal-Based Synfuel Product Build-Up Rates
In Sections 2.2.2.1 and 2.2.2.2, the number of coal conversion plants
on-stream for the three time periods was given in accordance with Scenarios
I, II, and III. In this section, the flows of the individual products
produced by the coal liquefaction plants are given (Figures 7 through 9).
The coal liquefaction products considered are: high-Btu gas, LPG,
gasoline, naphtha, middle distillate, and residuals. Each coal
gasification process has only a simple major product—either low-, medium-.
or high-Btu gas, and the coal gasification build-up rates were considered
in Section 2-1.
For each coal conversion process, for each coal feedstock, and for
each set of process operating conditions, a distinct product slate results
(References 19-24). The product flows presented are taken as most likely
given the three scenarios, and are based on the current published design
conditions for the processes. A detailed breakdown of the products is
taken from the plant design; the products are classified as being high-Btu
gas, middle distillate, naphtha, etc.; the flow rates of the products are
normalized to a 0.05 MMBPD plant; and then the product flow rates are
multiplied by the number of plants given in the plant build-up scenarios to
give the total flow for each major product. Although two products may have
a similar boiling range, their toxicities may be very different; therefore,
placing the products into boiling range and composition categories gives
only an approximate understanding of the total magnitude of the environ-
mental problems posed by their transportation and utilization.
45
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MMBPO
Gasoline
1980
^~ Middle Distillates
??OTmrrW?miwiW': High-Btu Gas
Gasoline
Naphtha
Middle Distillates
Residues
1984
1988 1992
YEAR
1996
2000
Indirect
Liquefaction
Direct
Liquefaction
Figure 7. Coal Liquefaction Produce Build-Up for Scenario I
MMBPD
Gasoline
1980'
S Middle Distillates
LPG
Naphtha
Middle Distillates
Residues
1984
1988 1992
YEAR
1998
Indirect
Liquefaction
Direct
Liquefaction
Figure 8. Coal Liquefaction Product Build-Up for Scenario II
46
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3.0
2.5
MMBPO
2.0
1.5
1.0
0.5
Gasoline
^=1 Middle Distillates
High-Btu Gas
LPG
Gasoline
=£ Naphtha
Middle Distillates
Residues
1980 1984
1988 1992
YEAR
1996
Indirect
Liquefaction
Direct
^ Liquefaction
Figure 9. Coal Liquefaction Product Build-Up for Scenario III
47
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SECTION 3
MARKET ANALYSIS OF SYNFUEL PRODUCTS AND BY-PRODUCTS
This section describes an analysis of the regional market development
of synfuel products and by-products. This analysis is based on the survey
of existing petroleum and natural gas marketing systems discussed in
Appendix D and the data developed in Section 2 on the type and number of
synfuel plants required to meet the three synfuel production scenarios.
Specifically, this section discusses: (1) synfuel plant siting and antici-
pated regional synfuel production rates; (2) synfuel product utilization;
and (3) likely regional distribution and utilization of synfuel products
and by-products in the ten federal EPA regions in the U.S. An overview of
this section is presented in the next four paragraphs.
The shale-based commercial synfuel plants will be located mostly in
the Colorado, Utah region where most oil shale resources are located.
However, the exact locations of commercial coal-based synfuels plants are
difficult to predict at this time. But it is very likely they will be
located in regions with abundant coal resources, which means they will be
located in EPA Regions III, IV, V, VI and VIII. The major synfuel products
will be gaseous products consisting mainly of high-Btu gas, medium-Btu gas,
low-Btu gas, and liquefied petroleum gas; light distillates consisting
mainly of gasoline; middle distillates consisting primarily of jet fuel,
kerosene, and diesel oil; and residuals consisting mainly of heavy fuel
oil; and petrochemicals. The high-Btu gas will be used primarily as a
heating fuel in industrial, commerical, and residential sectors as a sub-
stitute for natural gas. Medium-Btu gas will be used as a boiler fuel as
well as a chemical feedstock. Its primary chemical feedstock use is likely
to be for the production of methanol. Low-Btu gas will be limited to
en-sit? use in industrial processes as a fuel and not as a chemical feed-
stock. Liquefied petroleum gas will be used for domestic heating, as an
engine fuel, and for the production of ethylene and propylene, as well as
for the manufacture of synthesis gas. Gasoline, which forms the bulk of
light distillates, will be used primarily for automobiles. Middle dis-
tillates will be used primarily as a industrial, utility, and marine
application. They will also be used for the production of lubricants,
metallurgical oils, roof coatings, and wood perservative oils.
Shale-derived synfuel will be introduced into the petroleum market
around 1985 primarily to serve the transportation market. According to
Scenario II, which will be used as a baseline scenario for discussion in
this section, as much as 80,000 BPD of shale oil will be produced by 1987.
48
-------
One major customer of shale oil is likely to be the Department of Defense.
Two Air Force Bases in the West—Mountain Home AFB in Idaho and Hill AFB in
Utah—will probably be the major users of shale oil for their aircraft
testing program. They could consume as much as 20,000 BPD by the late
1980s. The bulk of the remaining shale oil produced is likely to be used
within EPA Region VIII (which includes the states of Utah and Colorado), at
least during the early years of production. As the production capacity
increases starting in the late 1980s, as much as 0.2 MMBPD of shale oil
could be shipped via an existing pipeline system to the Midwest region,
which is in EPA Region V. There, shale oil is likely to be used mainly by
the transportation sector.
The largest and earliest adoption of high-Btu gas production is likely
to occur in EPA region VIII as part of the Great Plains gasification
project. The gas from this project is likely to enter Region V. High-Btu
gas from subsequent plant build-ups in Region VIII will be entering Region
VI, that is Iowa, Kansas, Missouri, and Nebraska. High-Btu gas from plants
built in Region VI, New Mexico being a likely location, may enter gas
markets in Arizona, California, and Nevada which constitute Region IX. Any
high-Btu gas from plants built in the Middle Atlantic region, for example
in Pennsylvania, will be consumed within the region. As per our nominal
scenario (Scenario II), the U.S. could be producing as much as 0.09 MMBPD
of medium-Btu gas by 1987. Likely locations are Tennessee, New Mexico, and
Montana. These plants are very likely to be used in a captive mode by
industries to supply some of their fuel and chemical feedstock needs. For
example, they could be utilized by the chemical companies as a source of
synthesis gas for the production of methanol and ammonia. During the 1990s
when the production of medium-Btu gas is expected to increase
substantially, industrial parks consisting of medium-Btu gas facilities
with multiple users may come into existence.
Initially, coal-derived petroleum substitutes will be produced by
plants using indirect liquefaction processes. These are likely to be
located in Region VIII where state-of-the-art technology can use non-caking
coal available in that region. Gasoline will be the principal product from
these plants. Initially, the bulk of this production will be consumed
within the region. Any excess may be shipped to the midwest market.
During later years, plants using advanced indirect processes located in
the East could be supplying industrial areas of New York and New Jersey.
Direct liquefaction facilities are likely to be located primarily on the
Illinois, Kentucky, and West Virginia area. Fuel oil will constitute the
bulk of direct liquefaction supply. They are likely to be used primarily
in the utility, residential, and commercial sectors. Since some of the
heavy fuel oil products are not suited for pipeline transportation, they
will most likely take advantage of the extensive rail system in the east
and midwest. Tank trucks will also move large volumes. Liquefied petro-
leum gas is another product of direct liquefaction plants. Some of it
meant for the petrochemical industry is likely to be shipped to the Texas
area where most of the large petrochemical complexes are presently located.
The rest could be consumed in the regions where they are produced.
49
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3.1 LIKELY LOCATION OF SYNFUEL PLANTS
3.1.1 Oil Shale Plant Location
The oil shale resource is widely distributed in the United States.
However, initial commercial interest centers on the 600 billion barrels of
rich resources in the Green River Formation of Colorado, Utah, and Wyoming
as indicated in Figure 10. These deposits consist of marlstones containing
kerogen, an organic substance from which oil can be derived. Several oil
shale projects are presently in different stages of development in Colorado
and Utah, both of which are within the jurisdiction of EPA Region VIII.
The anticipated progress of these projects serves as a basis for the
development of the three oil shale scenarios discussed in Section 2.
The maximum likely hydrotreated shale oil production rates in Colorado
and Utah for Scenario II during 1980-1987, 1988-1992, and 1992-2000 are
given in Table 18.
TABLE 18. MAXIMUM ANTICIPATED SHALE OIL PRODUCTION RATE FOR SCENARIO II
State
Maximum Production Rate (OOOBPD)
(thousands of barrels per day)
1980-1987
1988-1992
1992-2000
Colorado
Utah
49
28
290
120
310
120
3.1.2 Coal Conversion Plant Location
The identification of likely locations for commercial coal conversion
plants is more uncertain than for oil shale plants because of the compara-
tive incipient nature of the commercial coal conversion industry. It is
anticipated that commercial coal conversion plants will be dispersed
throughout the midwestern and eastern states. Their exact location is
likely to be governed by a number of factors, some of which are discussed
in this section.
The potential coal synfuel resource in the U.S. is 11 trillion tons.
The coal resources most likely to be used for synfuel production are shown
in Figure 11. Sixty percent of this resource is concentrated in Montana,
Illinois, Wyoming, Alaska, and North Dakota. Twenty three percent is
located in Colorado, West Virginia, Pennsylvania, and Kentucky. A pro-
jected standard size synfuel plant designed to produce 50,000 BPD of oil
equivalent synfuel products will require about 20,000 to 40,000 tons of
coal per year. Under average conditions of conventional mining and
50
-------
.- y * " " i. ?JL =A i \ XLA^-
NT. T -f VON r • c '« iN-V^l-
^_y_V rwsfvAr
\—P* » it — '*• s—^T '*
W" /^AN JUAN I ^""V^f'C
t—fc/ i- A r-; / .1 v-^
"i 1 ^*
^ I M^
: c._i.6««if:- /f5-
-xA .A SAN JUAN
-i l^vv
Vt5
EXPLANATION
Green River Formation conlaining shale
10 or more feet thick, averaging 25
or more gallons of oil per ton
Upper Colorado River drainage basin boundary
Federal lease tracts
x C-a
DC-b
0 U-a
OU-b
I ^^J :-£;(
; SAN JUAN 1> /
'"'"":! NEW MEXICOJ
Source: U.S. Department of Interior/Geological Survey,
Synthetic Fuels Development: Earth-Science
Consideration, GPO, Washington, DC, 1979.
"»
•i •
200
ZOO MILES
_ |
300 KIlOMCUnS
Figure 10. Oil Shale Deposits Most Likely To Be Used for Synfuel Production
-------
tn
ro
!OS <00 tOOmOMI'DTj
Source:
U.S. Department of Interior/Geological Survey, Synthetic Fuels Development: Earth-
Science Consideration, GPO, Washington, DC, 1979.
EXPLANATION
Coal region* having
potential lor synfuel
development
Other cotl regions
No coal
Figure 11. Coal Resources Most Likely to be Used for Synfuel Production
-------
operation, about 12 to 24 million tons of coal reserves will be needed to
supply each plant for one year. Over the estimated 30-year life span of a
plant, between 360 and 720 million tons of coal reserves will be required.
In some coal regions, a substantial part of the identified resources is
located in beds that are too thin to meet the present requirements of
iarge_scale mechanized mining. Coal quality differs from deposit to
deposit and region to region, and greatly affects the coal's utility for
various synfuel processes. The caking tendency of coal is particularly
important; first-generation coal conversion technology favors noncaking
western coal. These are some of the geologic constraints that govern the
location of coal conversion plants. Based on the above geologic con-
straints, coal synfuel plants will most likely be located in the following
five EPA regions: Middle Atlantic (Region III), Southeast (Region IV),
Great Lakes (Region V), Southwest (Region VI), and Mountain (Region- VIII).
These regions are indicated in Figure 12.
Other factors (References 25, 26, 27, 28) that are likely to influence
the location are:
Water availability
Technology development status
Proximity to primary markets
Existing product distribution systems
Current government- or industry-funded projects
Industry interest.
A weighted average ranking procedure was developed to take into
account these factors for locating the coal synfuel plants in the five
chosen EPA regions during different time periods and for different produc-
tion scenarios. For Scenario II, the results are indicated in Table 19.
Coal conversion plants will initially be concentrated in the western
states. As the technology advances, more plants are likely to be located
in the eastern part of the country.
3.2 SYNFUEL PRODUCT UTILIZATION
The major synfuel products would essentially replace the petroleum and
natural gas products currently in use. The products can be grouped into
five broad categories:
1. Gaseous Products
High-Btu gas
Medium-Btu gas
Low-Btu gas
Liquefied petroleum gas (LPG)
53
-------
en
HAWAII
Figure 12. Likely Locations for Synthetic Fuel Plants
-------
TABLE 19. NUMBER OF COAL CONVERSION PLANTS NEEDED ON-STREAM TO MEET THE
REQUIREMENTS OF THE NOMINAL PRODUCTION SCENARIO SCENARIO II
Process
Indirect Liquefaction
Fischer-Tropsch
Mobil M
Advanced Indirect
Advanced Indirect
Advanced Indirect
Subtotal Indirect
Subtotal Product (10 8PD)
Direct Liquefaction
Subtotal Direct
Subtotal Product (103 BPO)
Total Liquefaction
Total Product (103 BPD)
High-Btu Gasification
Lurgi Fixed-Bed
Lurgi Fixed-Bed
Lurgi Fixed-Bed
Lurgi F]»ed-8ed
Advanced Fluid-Bed
Total High-Btu Gasification
Total Product (10^ BPD)
Low/Medium-Btu Gasification
Lurgi Fixed-Bed
Lurgi Fixed-Bed
Lurgi Fixed-Bed
Texaco Partial Oxidation
Total Low/Mediura-Btu Gasification
Total Product (103 BPD)
Regional Total Products (10^ BPO)
Indirect Liquefaction
Direct Liquefaction
High-Btu
LOM/Mediutn-Btu
Regions
VIII
VIII
IV
III
III
III
IV
V
VIII
VIII
VIII
VI
III
VIII
VIII
VI
IV
VIII
IV
III
III
IV
V
VIII
VI
III
VIII
VI
III
States
North Dakota
Wyoming
Kentucky
Pennsylvania
West Virginia
West Virginia
Kentucky
11 1 inois
North Dakota
Wyoming
Montana
New Mexico
Pennsylvania
North Dakota
Montana
New Mexico
Tennessee
Number of Plants
1980-87 1988-92
1
1
-
-
-
2
100
-
1
1
50
3
150
1 1
1
1
1
-
1 4
42 166
2
1 2
1 2
1 3
3 9
90 270
100
-
_
.
50
42 126
4;
-
30 120
30 60
30 90
on Strear
1993-2000
2
2
3
3
3
i:-
e;o
•
t
4
7
350
2C
1 03:
i
i
i
i
•>
6
25:
3
3
3
6
U
450
200
150
300
50
100
200
126
ir
?-
ISO
90
1?0
Total US Coal
Conversion Products (10 BPD)
132
5SS
55
-------
2. Light Distillates
Gasoline
Naphtha
3. Middle Distillates
Jet fuel
Kerosenes
Diesel oil
4. Residuals
Heavy fuel oil
Lubricants
Wax
Asphalt
5. Petrochemicals
In general, the suppliers interviewed in this study agreed that there
will be no discernible or significant differences in the products produced
from synfuels compared to products from petroleum or natural gas.
According to the users interviewed, however, it is not clear that current
specifications are sufficient to guarantee performance and environmental
acceptability. Of the synfuel products being considered, liquid products
derived from coal, if used directly, are perceived as most different from
conventional products in their composition and toxicity.
3.2.1 Gaseous Products
High-Btu gas offers many of the advantages of direct coal usage but
does not have some of the environmental drawbacks of burning coal directly.
It has the same heating value as natural gas and, therefore, can substitute
for natural gas in almost all its applications. High-Btu gas:
0 Can use the vast coal resource base in U.S.
0 Can use the extensive existing pipeline network
0 Requires no modification or adjustment of the equipment of
conventional gas consumers
0 Causes very little environmental pollution at the point of
consumption.
Its larger application is likely to be as a heating fuel in
industrial, commercial, and residential use. However, its possible small-
scale use as a fuel for internal combustion engines for stationary and
mobile application cannot be ruled out. The possibility also exists for
current users of natural gas for chemical feedstock to use high-Btu gas
56
-------
instead, if it is piped to the plant site at competitive rates. The
strongest potential markets for high-Btu gas are likely to be Midwestern
and Middle Atlantic regions, primarily as a result of the large quantities
of oil consumed in their industrial sectors.
Medium-Btu gas offers many of the advantages of high-Btu gas but at
lower cost. It can be burned in existing natural gas- or oil-fired boilers
with only minimal expense for retrofitting. Transportation of medium-Btu
gas would require a dedicated pipeline, but preliminary evaluations have
shown that it can be pipelined up to 200 miles economically. Therefore, it
is possible that a medium-Btu gasification plant could, for environmental
reasons, be located far from an industrial area and still economically
serve the area. Finally, medium-Btu gas is less expensive to produce than
high-Btu gas because investment in shift and methanation units is not
required, and the energy losses associated with these process steps are
avoided. In addition to its utilization as a boiler fuel, medium-Btu gas
is a potential source of feedstocks for the chemical industry. Ammonia and
methanol are now made from CO and hL produced by reforming natural gas.
These two basic chemicals have many uses in the manufacture of other more
complex chemicals.
It appears that high- and medium-Btu gas will be utilized by major
energy-consuming industries such as food, textile, pulp and paper, chemi-
cals, and steel. Only chemical, petroleum, and steel industries will
require enough fuel gas at a single location to economically justify the
dedication of a single gasification plant. Other industrial plants will
have to share the output distributed by pipeline from a central gasifier or
tap into existing natural gas pipeline systems for their need.
The major characteristics of low-Btu gas are its high nitrogen
content, its low carbon monoxide and hydrogen content, and its resulting
heating value--typically below 150 Btu/Scf. Because of its high nitrogen
content and low heating value, it cannot be economically pipelined over
long distances. A plant producing low-Btu gas would, therefore, have to be
located on-site or relatively close to the user. This constraint severely
limits the potential size of low-Btu gas plants and would not typically
allow the economy of scale that would be gained from large plants serving
multiple customers. Low-Btu gas flame temperature is about 13 percent
lower than that of natural gas. Because of these characteristics, low-Btu
gas is limited to on-site use in industrial processes requiring tempera-
tures below 2800 to 3000°F, and is generally unsuitable for use as a chem-
ical feedstock. Further, because of its low energy density it requires
significant equipment modifications for retrofit applications. Today there
are operating and planned low-Btu gasifiers in the U.S. for:
• Kiln firing of bricks
• Iron ore pelletizing
• Chemical furnance
t Small boilers.
57
-------
The three main constituents of LPG are propane, butane, and isobutane.
Propane is the lightest of the three, has the lowest vaporization point,
and is the most abundant. LPG is liquefied under moderate pressures. At
60°F butane requires pressurization of 40 pounds per square inch or more to
be liquefied; propane requires 110 pounds per square inch or more. Butane
liquefies under atmospheric pressure at 32°F; propane at -44°F. By con-
trast, natural gas will not liquefy at atmospheric pressures above -259°F.
Liquefying the gas provides a highly efficient and safe method of storing
and transporting the product: the fluid occupies only l/270th the space of
the gas, which returns to its natural state when released to the atmosphere
under normal pressure. LPG has applications for industrial, domestic, and
transportation uses. Although LPG is currently produced either from
natural gases or crude oil,.the introduction of coal-based LPG is not
likely to affect its use pattern. For domestic application, LPG is used
mainly as a fuel for cooking and for water and space heating. It can also
power refrigerators and air conditioners. LPG is also used on farms for
crop drying, tobacco curing, defoliation, and frost protection. It also
powers trucks, pumps, standby generators, and other farm equipment.
Commercial establishments such as hotels, motels, and restaurants use LPG
much as the homeowner does. As an engine fuel, its minimal emissions allow
it to be used indoors, which explains its wide popularity in fork-lift
trucks. This same feature makes it a desirable fuel in congested areas for
buses, taxis, and delivery trucks. In industry, coal-derived LPG may find
a large number of diverse uses. Apart from use as a fuel in processes that
require careful temperature control (glass, ceramics, and electronics) or
clean combustion gases (drying of milk, coffee, etc.), LPG is also used in
the metallurgical industry to produce protective atmospheres for metal
cutting and other uses. The chemical industry, particularly on the U.S.
Gulf coast, uses petroleum gases for cracking to ethylene and proplyene as
well as for manufacturing synthesis gas. Another use of LPG is to enrich
lean gas made from other raw materials to establish proper heating value
levels. On a volume basis, LPG production in the U.S. exceeds that of
kerosene and approaches that of diesel fuel. About 24 percent of LPG pro-
duction is used by the chemical and synthetic rubber industry, 46 percent
is used for residential and commercial use, and 10 percent is used for
automotive use: the remaining LPG is distributed among other industrial
and agricultural fuel use. By EPA region, the largest amount of LPG (0.36
MMBPD) is at present marketed in Region V. Currently about 70 percent of
all LPG is extracted from natural gas and 30 percent is refined from crude
oil. With the anticipated shortfall in the supply of these crudes, the
resulting shortage of the LPG will be met to some extent by LPG from
synfuel plants.
3.2.2 Light Distillates
Gasoline, a major light distillate, is generally defined as a fuel for
reciprocating, spark-ignition internal combustion engines for automotive
ground vehicles of all types, reciprocating aircraft engines, marine
engines, tractors, and lawn mowers. Other small-scale uses include fuel in
appliances such as field stoves, heating and lighting units, and blow
torches. The primary use of gasoline produced from coal will be for trans-
58
-------
portation applications. Currently, U.S. consumption of petroleum-derived
gasoline is almost 6.8 MMBPD, corresponding to about 40 percent of the
total petroleum consumption. Most refiners produce and market more than
one grade of motor gasoline, differing principally in anti-knock quality
and additives. Refiners also change the volatility properties of their
motor fuels, depending on the atmospheric temperatures at which the vehicle
is to operate. Winter gasoline is the most volatile and summer gasoline
the least volatile.
Naphthas serve many industrial and domestic uses. Their primary
market is the petrochemical industry where they can be used to manufacture
solvents, varnish, turpentines, rust-proofing compounds, Pharmaceuticals,
pesticides, herbicides, and fungicides. However, preliminary analyses
indicate chat a relatively small amount of coal-derived naphthas will enter
the market.
3.2.3 Middle Distillates
The markets for middle disti 1 lates--essential ly jet fuel, kerosene,
diesel oil, and heating oil — are jet aircraft, gas turbines, and diesel
engines used for transportation and stationary applications, and resi-
dential and commercial heating. The major use of distillate fuel in the
United States is for central home heating. The distillate heating oil
generally falls in the No. 2 classification of the industry's commercial
standards and is known as No. 2 fuel oil, as well as by various individual
company brand names. Heating oils include petroleum cuts boiling from
about 350 to 650°F. They are very much like diesel fuels and, in fact, in
some areas these products are interchangeable. Kerosene is another product
used for such applications as cooking and sometimes is referred to as No. 1
fuel oil or range oil. Its major advantage over heating oil is that it has
a much lower tendency to form carbon deposits. With the introduction of
synfuels into the market place it is anticipated that products comparable
to those will be derived from petroleum.
3.2.4 Residuals
The market for residuals, consisting mainly of fuel oil, is primarily
for industrial, utility, and marine fuel. Fuel oil meeting the specifi-
cations of Nos. 4, 5, and 6 fuel oil will come under this category.
Currently, petroleum-derived No. 6 fuel oil is probably the most widely
used residual product for industrial and utility fuel. Other applications
for residuals include preparation of industrial and automotive lubricants,
metallurgical oils, roof coatings, and wood preservative oils. Coke is
another likely useful product from residue. Wax from synfuel liquid
residue is likely to be used for manufacturing sanitary containers, waxed
food wrappers, candles, drugs, cosmetics, rubber, textiles, adhesives,
crayons, polishes, and paint removers.
59
-------
3.2.5 Petrochemical Feedstocks and Other By-Products
In addition to their primary use as fuel, many synfuel products are
likely to be used by the petrochemical industry as feedstocks for the
production of petrochemicals and other byproducts. More than 3000 petro-
chemicals and byproducts are now derived from petroleum and natural gas-
based feedstocks. These include the primary petrochemicals such as
ethylene, propylene, benzene, toluene, xylene (B-T-X group), and butadiene.
Other petrochemical derivatives include synthetic fibers, plastics, rubber,
detergents, solvents, sulfur, ammonia, fertilizers, pesticides, and carbon
black. A small percentage of these petrochemicals and other byproducts
will be displaced by feedstocks produced from synfuel s entering the
marketplace.
The primary feedstocks for petrochemicals and other products are
likely to be produced from three synfuel feedstock sources: naphtha,
medium-Btu gas (synthesis gas), and liquid petroleum gas (LPG). Direct
coal liquefaction will be a major source of naphtha. Naphtha may also be
produced as a byproduct of some coal gasification processes, for example,
the Lurgi gasifier. Medium-Btu gas (synthesis gas) will be used to produce
ethane, propane, and butane, which in turn are used as feedstock for the
production of petrochemicals and other byproducts. It is expected that
about 50 to 75 percent of the medium-Btu gas will be used by the petro-
chemical industry, with the remainder used for other industrial applica-
tions. The use of LPG offers another source for petrochemicals and other
byproducts feedstocks. About 24 percent of the LPG produced from synfuels
will be used by the petrochemical industry, while the remaining 76 percent
will be used by other industries and as an automobile fuel. In addition,
some of the other major synfuel products, for example, SNG, syncrude, and
methyl fuels, could be used to some extent for petrochemical feedstocks.
However, because it is expected that these products will be used primarily
to displace current oil and natural gas now servicing transportation,
residential, commercial, utilities, and industrial sectors, only a small
portion, if any, will be used as feedstocks.
Naphthas may be used in many industrial and domestic applications. In
addition to their primary use as feedstock for primary petrochemicals, they
can be used to manufacture other byproducts such as solvents, varnish, tur-
pentines, rust-proofing compounds, Pharmaceuticals, and pesticides. To
further assess the utilization of petrochemical feedstocks and other
byproducts, naphtha is discussed in terms of one of its major derivatives,
benzene. More data are available for benzene than for the other five
primary petrochemicals, which are discussed in Appendix D.
Based on current geographical utilization trends, the Gulf Coastal
states, Region VI, and the Great Lakes states, Region V, will be the major
consumers of the primary petrochemicals and their derivatives produced from
synthetic feedstocks. Region VI will consume about 82 percent of the total
benzene produced. Also, it is expected that this region will use 80
percent or more of all the feedstocks produced nationally to manufacture
petrochemicals and other byproducts. The Great Lakes region is expected to
60
-------
be the next largest consumer, using 4 percent. Detailed regional consump-
tion in terms of relative quantities of petrochemicals and other byproducts
is discussed in Section 3.3.
3.3 REGIONAL MARKET PENETRATION OF SYNFUEL PRODUCTS
Oil shale-derived synfuels will be introduced into the petroleum
market by about 1985, and, based on Scenarios I and II, as much as 0.08 to
0.2 MMBPD of shale oil can enter the market by 1987. The refined shale oil
products will primarily serve the needs of transportation sectors. Around
1987, according to the nominal scenario, about one high-Btu gasification
plant will be on-stream supplying 0.04 MMBPD of synthetic natural gas to
the natural gas pipeline system. By this time two or three medium-Btu
gasification plants may also be constructed but will be operated in a
captive mode, possibly by chemical industries. The commercial effect of
coal liquefaction technology will not be felt until 1992, according to
Scenario II. Around that time, it is expected that two indirect lique-
faction plants and one direct liquefaction plant may come on line. They
will be supplying the transportation, industrial, utility, commercial, and
residential markets. However, the true effect of coal liquefaction in the
marketplace will not be felt until the 1993-2000 time period, when up to 1
MMBPD of coal-derived liquid products will be entering the market. The
likely use pattern of synfuel from different sources is indicated in Figure
13. As much as possible, synfuels are likely to be utilized within or near
the region where they are produced. For the purpose of this study,
regional classification of the continental United States is based on EPA
region. It is also assumed that, as much as possible, synfuels will use
existing modes of transportation; no new pipelines are likely to be built
for transporting synfuels, except for some feeder lines.
One likely regional build-up of coal conversion plants for Scenario II
was indicated earlier in Table 19. This will form the basis for discussing
the movement and utilization of coal based synfuel products in our
subsequent discussions.
3.3.1 Shale Oil
Oil shale-derived synfuels will be introduced into the petroleum
product market around 1985, and, based on Scenario II (the nominal
scenario), up to 80,000 BPD of shale oil will be produced in the Colorado-
Utah region by 1987. Initially, it is expected that the hydrotreated shale
oil will be refined in the Rocky Mountain area either separately or as a
blend. Assuming that the hydrocracking refining process, which is likely
to yield products that are most desirable, is used, we can expect up to
57,000 BPD of middle distillates, 13,000 BPD of gasoline, and 7,000 BPD of
residuals to enter the market. It is very likely that the refined prod-
ucts, which consist mainly of middle distillates, will be entirely absorbed
by the transportation sector of the Rocky Mountain Area, Region VIII. This
region is currently a net importer of refined transportation fuel. One
major customer is likely to be the Department of Defense (DOD).
Approximately 90 percent of DOD's current total consumption of 413,000 BPD
is mobility fuel. Two Air Force bases in the West Mountain Home AFB in
61
-------
cr>
r\j
MAJOR SVNFUEL PRODUCTS/
BY-PRODUCTS
TRANSPORTATION
SECTOR
Indirect Cot
10f»
Products
Dlrtcl
Liquefaction
Products
Catl Uilflcltlon
Product!
• Uiollnt
• Ktddlt
iut»
e.g.. J*t
FlMl.
Oltiel.
• Nlddlt DUcllliui
(« 9 . Jet Fu«l,
Dteitl . M
• ntddU
OUtlllltii
(1.9-.
Fu.1.
OKtel.
uroscnt)
• SNG
COAL
GASIFICATIONS
t.g . H»rln«
Fuili. LubrUtntl)
• (Uphtni
I LfO
light FMI oil)
• ten duals
(«.g . Ktrint
Fu.li.
LubrUlntt )
INDUSTRIAL
SECTOR
COMMERCIAL
• RESIDENTIAL
SECTOR
COAL
LIQUEFACTION
(DIRECT
INDIRECT
PROCESSES)
NOTE:
Penetration of Sh.le 011 Into the Utilities .nd
ind Resldenttsl sector Is expected to be minimal and
therefore not highlighted
Figure 13. Synfuel Utilization During 1985-2000
-------
Idaho and Hill AFB in Utah plan to switch to 100 percent consumption of
synthetic aviation turbine fuel derived from shale oil. Their near-term
requirement is likely to be 5,000 to 10,000 BPD for their aircraft testing
program. The residual that is produced is likely to be used within EPA
Region VIII as boiler fuel in the industrial or utility sector. In view of
the small quantity of this initial supply, the residual may possibly be
blended with petroleum-derived fuel oil. Most of the petroleum products
will be transported by trucks within the region from the refineries.
The shale oil use pattern for Scenarios I and III is not likely to be
different during this time period. However, total quantity is likely to be
as high as 0.3 MMBPD. During the 1988-92 time period, the quantities of
shale oil produced are likely to increase substantially. For Scenario III,
production could be as high as 0.75 MMBPD. However, the nominal scenario
projects a production rate of only 0.40 MMBPD. During this period, hydro-
treated shale oil is likely to be transported to the upper Midwest for
refining. According to interviews with potential suppliers (Appendix A),
there is currently about 0.2 MMBPD open refinery capacity near Chicago,
St. Louis, and Detroit. It is assumed that about 0.2 MMBPD of hydrotreated
shale oil could be supplied to the upper Midwest, which essentially belongs
to EPA Region V and constitutes a major section of Petroleum Administration
for Defense District 2 (PADD2) as well. In Region V there is also a heavy
demand for transportation fuel, and shale oil-derived fuel will be used
primarily by the transportation sector. This quantity could be as high as
0.2 MMBPD. The residuals, which could amount to 0.03 MMBPD, will be used
primarily by the industrial and utility sectors in the region as boiler
fuel.
The demand for transportation fuels during the late 1980's is expected
to be about 10 MMBPD. Of this, about three to five percent is likely to
consumed by the military sector. A large amount of shale oil products
could be utilized by the military, possibly with a government synfuel pur-
chase guarantee program. It is possible, therefore, that during this time
period, about 10 percent of the 200,000 BPD of refined shale oil products
marketed in EPA Region VIII will be supplied to the military, including the
two Air Force bases Mountain Home AFB in Idaho and Hill AFB in Utah. The
remaining will be consumed by the civilian sector. The use pattern of
shale oil during 1993-2000 is not likely to be different.
3.3.2 Coal Gas
3.3.2.1 High-Btu Gas
The national goals scenario (Scenario I) projects that 0.5 MMBPD of
oil equivalent gas production could be achieved by 1992. A more realistic
scenario that considers impediments to the build-up of high-Btu gas (HBG)
production is described by the nominal production scenario, which predicts
only 0.17 MMBPD of gas by 1992. An accelerated production schedule of
1 MMBPD by 2000 occurs with Scenario III. For the purpose of discussing
the market penetration of HBG, Scenario II is used as a base case.
63
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The largest and earliest adoption of high-Btu gas production will
©ccur in Region VIII (Colorado, Montana, North Dakota, South Dakota, Utah,
and Wyoming). Initially, one 0.04-MMBPD capacity plant will come on line
in North Dakota during 1980-1987. Construction is now underway in North
Dakota on the Great Plains Gasification project. The project is to be
completed in two phases: the first phase (0.02 MMBPD) is scheduled for
completion in 1984, at which time construction on the second phase (0.02
MMBPD) will begin. HBG from the Great Plains project will enter markets in
Region V (Illinois, Indiana, Michigan, Minnesota, Ohio, and Wisconsin)
through the addition of a 365-mile, 20-inch SNG pipeline. The largest
end use of natural gas in Region V is for space heating. Space heating
will consume 60 percent (0.024 MMBPD) of the HBG and an additional 39
percent (0.0156 MMBPD) will be used by the industrial sector (Table D-9,
Appendix D). The major industrial natural gas consumers by sales for this
area are: (1) primary iron and steel; (2) service industry; (3) fabricated
metal products; (4) chemicals and allied products; and (5) the food
industry. Extensive storage facilities are located throughout Region V,
with 2,760 billion cubic feet of storage space (Table D-8, Appendix D).
Additionally, HBG supplied from North Dakota into Region V will remain at
0.04 MMBPD for all three time periods.
During 1988-92, two additional 0.04 MMBPD HBG plants will come on line
in Region VIII. One will be located in Montana and the other in Wyoming.
Current indications are that this 0.08 MMBPD will be used within the Region
VIII natural gas distribution network; however, significant amounts of the
HBG production may reach markets in Region VII (Iowa, Kansas, Missouri, and
Nebraska) through the addition of the northern border pipeline. Pipeline
construction is scheduled to begin in 1981. HBG production may also reach
Region VII via a pipeline system to the midwest owned by the participants
in the Wycoal project. The Wycoal project has requested funds from DOE to
construct a facility that would use Lurgi and Texaco gasification units.
Gas from these units in Region VII would be used primarily for space
heating by the residential and commercial sectors which consume 50 percent
of Region VII's natural gas (see Table D-9, Appendix D). Industrial use
amounts to 31 percent of the total consumption, with the largest consumers
in the area by sales as follows: (1) electric utility; (2) chemicals; (3)
food and kindred products; (4) primary iron and steel; and (5) carbon black
(Table D-10). Consumption within Region VIII would be for space heating by
the residential and commercial sectors, which currently consume 54 percent
of total natural gas consumption (Table D-9). The five largest industrial
users by sales for the region are: (1) electric utility; (2) petroleum
refining; (3) food and kindred products; (4) chemicals; and (5) services
(Table D-10). Additionally, the Crow Indians have requested funds from DOE
for a feasibility study of a HBG facility to be located near Billings,
Montana.
Region VI (Arkansas, Louisiana, New Mexico, Oklahoma, and Texas) will
be producing 0.04 MMBPD of HBG for the periods 1988-92 and 1993-2000; no
production is scheduled for 1980-87. At present, New Mexico produces and
markets five times more natural gas than it consumes. The bulk of New
Mexico natural gas enters markets in Region IX (Arizona, California, and
64
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Nevada). The average daily flow from New Mexico into Region IX is 0.64
MMBPD (4000 MMCFD). Therefore, HBG consumption may occur in New Mexico or
Region IX. The greatest consumption of natural gas in New Mexico, 35
percent, is for industrial service (Table D-9) of which electric utility
service is the largest consumer. Forty seven percent of the natural gas
consumed in Region IX is for space heating in residential and commercial
sectors (Table D-9). Industrial use is the next largest consumer, using 30
percent of the total market consumption (Table D-9).
For Region III, two advanced fluid-bed gasifiers are expected to be
built in Pennsylvania. Production will total 0.08 MMBPD from these two
plants during 1993-2000. No HBG production is expected in Region III
during 1980-87 or 1988-92. Consumption of the HBG will occur entirely
within the Pennsylvania natural gas system. According to Table D-9, almost
59 percent (0.0472 MMBPD) of the total 0.08 MMBPD HBG would be consumed by
the residential and commercial sectors for space heating. Another 37
percent (0.0296 MMBPD) would be consumed by the industrial sector. The
five largest industrial users of natural gas by sales for the middle
atlantic states (New Jersey, New York, and Pennsylvania) are: (1) primary
iron and steel; (2) glass products; (3) fabricated metal products; (4)
chemicals, and (5) manufacturing. Current information (Table D-9) indi-
cates that storage facilities in Pennsylvania are used at capacity levels;
consequently, HBG production would be displacing current natural gas sup-
plies from production fields in the southern U.S. Pennsylvania's ultimate
reservoir capacity is 800 billion cubic feet.
The preceeding analysis was concerned with the most likely production
build-up of HBG production Scenario II. Scenarios I and III are more
optimistic in their predictions of HBG build-up. The siting,
transportation routes, and end-use patterns in Scenarios I and III are
similar to Scenario II.
Scenario I sites HBG facilities in Regions III and VIII. For 1980-87,
seven plants (0.28 MMBPD) are scheduled to come on line in Region VIII.
Eleven plants (0.44 MMBPD) will be in operation during 1988-92 and
1993-2000. No HBG production is scheduled in Region III for 1980-87, but
one (0.04 MMBPD) plant is scheduled for 1988-92 and 1993-2000. End-use
consumption will remain the same.
Scenario III sites HBG facilities in Regions III and VIII. Region
VIII production is the same as for Scenario I (0.28 MMBPD in 1980-87, 0.44
MMBPD in 1988-92) except for 1993-2000. Production will then increase to
0.64 MMBPD from 16 plants. Region III is also the same for 1980-87, no
production is scheduled; 0.04 MMBPD is planned for 1988-1992; and
production will increase to 0.32 MMBPD from 8 plants in 1993-2000.
3-3.2.2 Low-/Hedium Dtu Gas
Scenario II sites medium-Btu gasification facilities in EPA regions
IV, VI, and VIII. For 1980-87, approximately 0.09 MMBPD of MBG is sched-
uled for production. Likely locations are Tennessee, New Mexico, and
65
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Montana. The medium-Btu gas could be used as a synthesis gas for producing
chemical products such as ammonia, which in turn could be used to manufac-
ture such products as fertilizers, fiber and plastic intermediates, and
explosives. During this time it is likely that one or two of these plants
could be producing methanol as well. The plant might be owned by an indus-
trial company primarily to serve its internal needs, which could be to
produce methanol or formaldehyde, a product with a number of end-use
applications. Some of the methanol produced during this time period could
possibly be utilized by organizations like EPRI to test its usefulness as a
turbine fuel. Interested organizations could test it for automobile use
also, but it is unlikely that methanol from these plants would enter the
open market directly on a large scale for public consumption. One reason
is the lack of a suitable marketing infrastructure. This fact was rein-
forced in the course of interviews conducted as part of this study. In any
case, not more than 40 percent of medium-Btu gas production in the country
is likely to be converted to methanol. The most likely users of medium-Btu
gas will be the chemical, steel, and primary metal industries. Chemical
industry use would be primarily as a feedstock; steel industry use would be
primarily for blast furnace injection; and primary metal use would include
annealing operations and burner application. For 1988-92 and 1993-2000,
the medium-Btu gas production could be 0.27 MMBPD and 0.45 MMBPD respec-
tively. During these periods, industrial parks consisting of medium-Btu
gas facilities with multiple users may come into existence.
During the different time periods, the use of low-Btu gas will be
limited to industrial fuel in such applications as kilns, chemical fur-
naces, and small boilers. Currently there are about 15 to 20 facilities in
the U.S. that use, or are in the process of beginning to use, low-Btu gas
for applications such as brick kilns, chemical furnaces, space heating, and
metal-process furnaces. The operators of these facilities include General
Motors Corporation, Caterpillar Tractors, and Dow Chemical Company. By
1980-87 the number of low-Btu facilities may be about 35, increasing to
about 45 by 1992. During 1988-92, the use of low-Btu gasification by
utilities in one or two demonstration units for combined cycle application
cannot be ruled out.
Scenario II is much more optimistic about the use of low-/medium-Btu
gas for different applications than is Scenario I. The Scenario II
projection for low-/medium-Btu gas by 2000 is 0.45 MMBPD, compared to 0.3
MMBPD projected in Scenario I.
3.3.3 Coal Liquefaction Products
A synfuel production build-up in line with national goals, as
proposed by the Synthetic Fuels Corporation, calls for a preliminary goal
of 0.5 MMBPD by 1987 and 2 MMBPD by 1992. But realization of this goal is
contingent on adequate federal funding; availability of material, equipment,
and labor; and smooth environmental permitting. Presently the Fischer-
Tropsch process is the only commercially demonstrated coal liquefaction
process, with the Mobil-M process ready for full-scale production within
the next five years. In recognition of the current state of the art,
66
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perhaps a more realistic leadtime and subsequent build-up of coal
liquefaction plants is embodied in a scenario that projects no large-scale
liquefaction plants until 1992. This nominal production scenario projects
a yield of 1 MMBPD by the year 2000.
This section investigates the direct and indirect coal liquefaction
facilities as projected, primarily, under Scenario II. The emphasis here
is on the movement of coal liquid crude or final products from liquefaction
plants to markets. Direct and indirect liquefaction are treated separately
because of their different products and projected geographic locations.
Based on likely plant sitings for Scenario II, the quantities of different
coal liquid products that are likely to be produced in different EPA
regions are indicated in Table 20. In addition to these products, the
Fischer-Tropsch process is likely to produce phenol and tar oil products as
well, which may be as much as 50 and 35 percent respectively by volume of
gasoline production.
3.3.3.1 Indirect Coal Liquefaction Products
Based on the plant build-up schedule, the nominal scenario (Scenario
II) projects two indirect liquefaction plants by 1992 and 13 by the year
2000. North Dakota and Wyoming could be the first to actually produce,
with Kentucky, Pennsylvania, and West Virginia surpassing western
production by the turn of the century.
SNG and gasoline constitute the bulk of indirect liquefaction
products. Depending upon the location of individual plants, pipelines may
be used to ship these products.
EPA Region VIII, North Dakota and Wyoming, is expected to be the
location of initial commercial production of coal liquids using primarily
the Fischer-Tropsch and Mobil-M processes. Using 1978 consumption as a
reference point for the use of gasoline and natural gas, it appears that
coal liquefaction products will satisfy only a part of local regional
demand. Currently, natural gas is used primarily in the residential (32
percent) and industrial (37 percent) sectors. SNG from indirect coal
liquefaction will most likely help satisfy this local regional demand. SNG
will move to areas of demand through the existing and proposed pipeline
network. Pipelines in the vicinity of proposed plants for EPA region VIII
are:
Plant Location Existing and Proposed Pipelines (Ref. 30)
North Dakota Montana-Dakotas Utilities Co. (existing)
Northern Border Pipeline Co. (proposed, 1981)
Pipeline from Great Plains Project (proposed)
(Ref. 29)
67
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TABLE 20. TYPES AND QUANTITIES OF COAL CONVERSION PRODUCTS
PRODUCED FROM PLANTS ON STREAM FOR THE NOMINAL PRODUCTION
SCENARIO SCENARIO II
Process/Products
Indirect Liquefaction
Fischer-Tropsch
SNG
Gasoline
LPG
Diesel Fuel
Residues
Mobil-M
Gasoline
Advanced Indirect
Gasoline
Advanced Indirect
Gasoline
Advanced Indirect
Subtotal Products
Direct Liquefaction
Naphtha
Middle Distillates
Residues
LPG
Naphtha
Middle Distillates
Residues
LPG
Naphtha
Middle Distillates
Residues
LPG
Subtotal Products
Total Products
High-Btu Gasification
Lurgt Fued-Bed
SNG
Lurqi Fixed-Bed
SNG
Lurgi Fixed-Bed
SNG
Lurgi Fixed-Bed
SNG
Advanced Fluid-Bed
SNG
Total Product
Low/Medium-Btu Gasification
Lurgi Fued-Bed
Medium-Btu
Lurgi Fixed-Bed
Medium-Btu
Regions States
VII North Dakota
VIII Wyoming
IV Kentucky
III Pennsylvania
III West Virginia
III West Virginia
IV Kentucky
V Illinois
VIII North Dakota
VIII Wyoming
VIII Montana
VI New Mexico
III Pennsylvania
VIII North Dakota
VIII Montana
Products Produced (ID3
1980-87 1988-92
32.60
14.50
0.10
2 50
0.70
50.00
--
;
100 00
-
15.40
18 70
10.00
5.90
50.00
150.00
42.00 42 00
42 00
42 00
42.00
42.00 168 00
60.00
30 00 60 00
BPD)*
1993-2000
65 20
29.00
0.20
5 00
1.40
100 00
150 00
150 00
150 00
650 00
15 40
18 70
10 00
5 90
30 80
37 40
20.00
11.80
61.60
74 80
40 00
26.60
350.00
100U 00
42.00
42 OU
42 00
42 OU
82 Ou
252.00
90 00
9U UO
(continued)
68
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TABLE 20. (CONTINUED)
Process/Products Regions States
Luroi Fixed-Bed VI New Mexico
Medium-Btu
Texaco Partial Oxidation IV Tennessee
Mediuro-Btu
Total Product
Regional Total Products
SNG VIII
Mediuro-Btu
LPG
Gasol me
Middle Distillates (Diesel)
Residues
Subtotal Products
sr.G VI
Medium-Btu
Subtotal Products
LPG V
Middle Distillates
Residues
Naphtha
Subtotal Products
Medium-Btu IV
Gasol me
LPG
Middle Distillates
Residues
Naphtha
Subtotal Products
SNG III
Gasol me
LPG
Middle Distillates
Residues
Naphtha
Subtotal Products
lotal U.S. Coal
Conversion Products
Products Produced (10J
1980-87 1988-92
30 00 60.00
30.00 90.00
90.00 270.00
42.00 158.60
30.00 120.00
0.10
64.50
2.50
0.70
72.00 346 00
42 . OC
30.00 60.00
30.00 102.00
5 90
18.70
10.00
15.40
SO 00
30.00 90.00
_
.
_
-
30.00 90.00
132.00 S88.00
BPO)*
1993-2000
90.00
180.00
450.00
191.20
180.00
0.20
129.00
5.00
1 .40
506.00
c:.oo
9C . 00
132 00
23.60
74.60
40. OC
61 .60
200 00
18C 0"
15C.OO
11.60
37.40
20.00
30.60
430 OC
84.00
300.0:
5 90
16 70
10.00
15.40
434 00
1702.00
•Sums may not equal totals due to rounding off
69
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Wyoming Montana-Dakotas Utilities
Colorado Interstate Gas Co.
Northern Utilities, Inc., Wyoming
McCulloch Interstate Gas Corp.
Kansas-Nebraska Natural Gas Co.
Wyoming Interstate Natural Gas System
(proposed)
In general, gas flows from Montana into North Dakota; therefore plants
located in North Dakota could help satisfy state-wide demand. Gas extrac-
ted in Wyoming flows into surrounding states, primarily Utah and Colorado.
Gasoline and other middle-distillate products from indirect coal lique-
faction will be used primarily by the transportation sector. Facilities to
move the other liquefaction products are not quite as accessible as the gas
pipelines. As of December 31, 1978, there was no sizeable petroleum prod-
uct pipeline capacity from North Dakota to other points (Reference 30).
For coal liquids that require refining, two crude pipelines move out of
North Dakota, one terminating in the middle of the state and one flowing as
far as Chicago. If marketable products are produced at the liquefaction
site, the plants should be located close to markets or new pipelines should
be brought on line. Based on 1978 consumption patterns, gasoline from
liquefaction plants in Region VIII could satisfy about one fourth of the
current regional consumption. Data on movements across Petroleum
Administration for Defense Districts (PADD's) indicate that the Rocky
Mountain area receives petroleum products via pipeline almost solely from
the Mid-Continent Area (PADD-2) (Reference 31). First-quarter 1978 statis-
tics estimate about 68,000 BPD of light petroleum products (Reference 32).
According to Scenario II, indirect liquefaction plants in Wyoming may be
producing 50,000 BPD of gasoline by 1992.
Should Wyoming gasoline consumption double by 1992, the coal
liquefaction gasoline could still satisfy all statewide demand, as shown
below.
States in EPA VIII OOOBPD Gasoline Consumption (Ref. 33)a
Colorado 103.2
Montana 35.8
North Dakota 30.3
South Dakota 32.0
Utah 49.0
Wyoming 24.2
aAnnual figures reduced to daily consumption (divided by 365).
Should there be sufficient production to satisfy state-wide demand,
excess gasoline could be shipped to Colorado and Utah and on to other
markets. Petroleum product pipelines from Wyoming are listed below:
70
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(OOOBPD)(Ref. 34)a
Company Point to Point Capacity
Pioneer Sinclair, Wyoming to Salt Lake City, Utah 32
Sinclair Sinclair, Wyoming to Denver, Colorado 14
Wyoming Casper, Wyoming to Rapid City, South Dakota _9_
Total 55
aAnnual figures reduced to daily consumption (divided by 365).
Although product pipelines exist in this area, the total existing
capacity would be required to handle the anticipated 1992 gasoline
production.
The nominal scenario projects a doubling of capacity from 1992-2000,
using the same processes in North Dakota and Wyoming. In the same period,
advanced indirect plants in Pennsylvania, West Virginia, and Kentucky are
projected to come on line and surpass western production with 150 MBPD in
each state. The primary product anticipated from the advanced indirect
liquefaction facilities is gasoline. The 1978 gasoline consumption figures
for EPA regions _LL and III are:
EPA Region State (OOOBPD)(Ref. 33)
II New Jersey 22
New York 403
III Delaware 20
District of Columbia 14
Maryland 133
Pennsylvania 393
Virginia 186
West Virginia 59
Data on cross-PAD district movements indicate that more gasoline flows
into PAD district I (Eastern Seaboard) than flows out. Figures for
November 1979 put gasoline inflow at 1,117 MBPD and outflow at 151 MBPD
(Reference 30). Should gasoline consumption remain the same, the projected
gasoline from coal liquids of 450 MBPD by 2000 could displace one-third of
the gasoline demand. While the largest product pipeline in the nation
moves products from the Gulf coast to the population and industrial centers
of the east, it completely bypasses Kentucky and West Virginia. In fact,
these two states, projected to be prime coal liquids producers, have no
major product pipeline and only limited crude facilities. Pennsylvania,
another projected producer, has a number of pipelines running through it
but all are in an east-west orientation. Besides displacing gasoline moved
into the region by pipeline, the liquefaction products could displace
water-shipped gasoline. From November 1979 statistics, it appears that
71
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gasoline constitutes about 50 percent of the petroleum products moved over
water. Eastern indirect coal liquefaction (450,000 BPD) could displace
much of that shipped via tanker and barge.
By 1993-2000, pipelines may be built to transport gasoline from
liquefaction plants to consuming centers such as Pittsburgh. From
Pittsburgh, final products could be incorporated into the existing network
and moved farther east to the industrial areas of New York and New Jersey.
Liquefaction plants in Pennsylvania have relatively easier access to
refineries and product pipelines. Should refining be required, refineries
operate in the Lake Erie area and the Philadelphia area, although excess
capacity is questionable. Products could be incorporated into the movement
via the Great Lakes to consumers from Erie or via pipeline from
Philadelphia to eastern consumers.
From existing storage capacity and inventory data for crude oil and
petroleum products, as well as from plans for new construction of storage
capacity, it appears that in the areas projected for coal liquefaction
plants there should not be any problem storing liquefaction products.
3.3.3.2 Direct Coal Liquefaction Products--
The nominal scenario projects direct liquefaction facilities primarily
in the Illinois, Kentucky, and West Virginia region. A product slate
consisting of naphtha, middle distillate, residual fuel oil, and LPG is
anticipated. Should the coal liquids from the plants require refining,
sufficient crude pipelines move through Illinois to refineries in northern
Illinois. If the light products from the direct process are available at
the point of liquefaction, numerous product pipelines also move through
Illinois to the north (Chicago) and east (Ohio and Pennsylvania). These
pipelines (Reference 34) are listed below:
Type
Crude
Crude
Crude
Crude
Crude
Crude
Product
Product
Product
Product
Product
Company
Explorer
Marathon
Texas Cities
Service
Chicap
Marathon
Sohio
Explorer,
Phil 1ips
Marathon
Marathon,
Buckeye
Sun
Ashland
Point to Point
Wood River, 111
Wood River, 111
Bluff City, 111
to Chicago, 111.
to Bluff City. Ill
to Chicago, 111.
Bluff City, 111. to Chicago, 111.
Bluff City, 111. to Lima, Ohio
Bluff City, 111. to Lima, Ohio
Wood River 111. to Chicago, 111.
Wood River, 111. to Chicago, 111.
Wood River, 111. to Chicago, 111.
Akron, Ohio to Pittsburgh, Pa.
Canton, Ohio to Pittsburgh, Pa.
Capacity
(OOOBPD)
290
315
161
490
315
26
327
90
48
45
30
72
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Although pipelines exist in this area, they carry mainly petroleum
crude and products from the Gulf Coast area. Pipeline availability and
refinery capacity are questionable.
LPG will most likely follow the same general pattern and be pipelined
and trucked to northern industrial areas. Likely pipelines are:
Size
Company Point to Point (Diameter In Inches)
Texas Eastern Cape Girardeau, Mo. to Marcus 20 to 6
Hook, NJ
Phillips St. Louis, Mo. to Chicago, 111. 8
Heavy products not suited to pipeline transportation will most likely
take advantage of the extensive rail system that stretches through
Illinois, Indiana, Ohio, and Pennsylvania. Tank trucks will also move
large volumes.
Indications are that direct coal liquefaction products will be
absorbed into the current distribution network and help satisfy local
demand or move to markets currently being served by product pipelines the
Chicago area and industrial east.
Indications are that residual products of direct coal conversion will
be used primarily in the utility sector as boiler fuel. Initially, dis-
tillates may be used for residential and commerical heating. Naphtha may
be used as a chemical feedstock material. LPG will find application both
as a chemical feedstock and as a heating fuel. Attempts will be made
during 1993-2000 to use distillates from direct liquefaction as turbine
fuel. Efforts to refine them for use in the transportation sector cannot
be ruled out. If this effort is successful, DOD could become a major
customer of direct liquefaction products with coal plants built in
Appalachia supplying Andrews Air Force Base in Maryland (Reference 35).
3-3.4 Petrochemical Feedstocks and Other By-Products
During 1980-1987, the feedstocks for petrochemicals and other
by-products will have to come from medium-Btu gas production. As shown in
Table 21, naphtha or LPG production in this time period per Scenario II is
negligible. The total quantity of medium-Btu gas produced is 0.09 MMBPD in
Regions IV, VI, and VIII. Considering the utilization patterns shown in
Tables D-15 and D-16, about 50 to 75 percent of the medium-Btu gas produced
in Region VI will be consumed by the petrochemical industry as feedstocks.
The medium-Btu gas produced in Regions VIII and IV will likely be for
captive use by other industries, unless some petrochemical industries are
built in these regions. It is possible that some of this medium-Btu gas
73
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TABLE 21. COMPARISON OF PETROCHEMICAL FEEDSTOCKS AND OTHER BY-PRODUCTS PRODUCED
TO MEET THE GOALS OF SCENARIO II VS. SCENARIO I AND SCENARIO IIL
Sources
Product of Direct
Liquefaction
Naphtha
Total
Medium-Btu Gasification
Synthesis
Total
Product of Indirect/
Direct Liquefaction
LPG
Total
Region
III
IV
V
IV
V
VI
VII
III
IV
V
VIII
Scenario II
Feeds tocks(103BPD)
1980-87 1988-92
15.40
15.40
30.00 90.00
30.00 60.00
30.00 120.00
90.00 270.00
5.90
0.10
6.00
1993-2000
15.40
30.80
61.60
107.80
180.00
90.00
180.00
450.00
5.90
11.80
23.60
0.20
41.50
Scenario
Feedstocks (
1980-87 1988-92
6.60
33.70
40.30
30.00 90.00
150.00 210.00
180.00 300.00
9.90
12.40
0.40 0.90
0.40 23.20
103BPO)
1993-2000
6.60
33.70
40.30
90.00
210.00
300.00
9.90
12.40
0.90
23.20
Scenario I
Feedstocks (10-
1980-87 1988-92
6.60
33.70
40.30
30.00 90.00
150.00 210.00
180.00 300.00
9.90
12.40
0.40 0.90
0.40 23.20
'BPD)
1993-2000
13.20
67.40
80.60
210.00
120.00
210.00
540.00
19.80
24.80
0.90
45.50
-------
produced in Regions IV and VIII could be used to manufacture ammonia and
methanol, which could eventually be used by the petrochemical industry to
manufacture other petrochemicals and by-products.
In comparing the product build-up rates of Scenario II with Scenarios
I and III, Table 21 shows that Scenarios I and III produce 0.09 MMBPD more
medium-Btu gas than Scenario II. This increase in feedstock production by
Scenarios I and III would provide for additional feedstock utilization in
Regions V and VIII for the manufacture of ammonia and methanol. The
products could be eventually used to manufacture other petrochemicals and
by-products, to be used in those regions.
During 1988-1992, all three primary sources of feedstocks will be
produced and will be more widely dispersed throughout the U.S. The major
difference between this time period and the earlier one is that naphtha and
LPG will be produced. Naphtha is produced as a product of direct lique-
faction in Region V. LPG is produced in Regions V and VIII. Medium-Btu
gas is still produced in Regions IV, VI, and VIII, the difference being an
increase in quantities over the last time period. The total quantities of
feedstocks produced, as shown in Table 21, are: naphtha-15,400 BPD;
medium-Btu gas 270,000 BPD; and LPG 6,000 BPD. The utilization of
these feedstocks is expected to parallel to some extent the current
regional consumption patterns shown in Tables D-15 and D-16. However,
because only a small amount of naphtha is produced, it is expected that it
will be used totally in Region V as a feedstock for other petrochemicals
and by-products or as feedstocks for other industrial use. for example.
gasoline production. The medium-Btu gas produced in Regions IV, VI, and
VIII is expected to be used for the same purposes discussed earlier in the
1980-1987 period. About 24 percent of the LPG produced in Regions V and
VIII can be used by petrochemical industries in Regions V and VI for
manufacturing petrochemicals and other by-products. The remaining 76
percent of LPG will likely be used for other industrial applications as
discussed in Section 3.2.1.
The 1993-2000 period will have the same types of feedstock production
as discussed for 1988-1992. The difference is that the expected quantities
of feedstocks increase significantly because of the increase in the number
of plants in operation by this time. Table 21 shows that naphtha produc-
tion in Region V increases four times, and medium-Btu gas production in
Region IV, doubles while Regions VI and VIII increase by one and one-half
times. LPG production in Regions V and VIII increases by four and by one
and one-half, respectively. In addition, about 15,400 BPD and 30,800 BPD
of naptha is produced in Regions III and IV. Also, about 5,900 BPD and
11,800 BPD of LPG is produced in Regions III and IV. The utilization
pattern of these feedstocks is expected to continue as discussed earlier
for the 1988-1993 period. The only exception may be that because the
naphtha and LPG production are increased four times and they are also produced
in Regions III and IV, some of these feedstocks are likely to be trans-
ported to Region VI. If these feedstocks are transported, the likely mode
will be by rail, and truck.
75
-------
3.3.5 Summary of Synfuel Product Utilization by Region
For the three production time periods identified for Scenario II, the
regional utilization of major synfuel products (SNG, LPG, gasoline, middle
distillates, and heavy distillates) are summarized in Tables 22, 25, and
31. In addition, detailed tables supporting each summary table show the
likely utilization by region and by consuming sector. The quantities shown
by consuming sector, using quantities utilized by region, are allocated on
a percentage basis consistent with current consumption patterns. Figures
14 through 16 show the quantities and transport patterns of synfuel
products within and outside of the production regions. In addition, the
tables present the current regional utilization patterns as well as the
likely utilization patterns expected for synfuel products.
Table 22 and Figure 14 show that during 1980-87 all products produced
from shale oil will be consumed in Region VIII. The major consuming
sectors of these products are shown in Table 23. During the same time
period, the SNG produced in Region VIII will be pipelined to Region V
industrial centers for utilization. Table 24 shows a breakdown by
consuming sectors for SNG.
As shown in Table 23, shale oil products in Region VIII could displace
about 16 percent of the regional gasoline, middle distillates, and residual
demand, while at the same time displacing about 9 percent of the region's
total energy needs. Table 24 shows that the SNG (from Region VIII) could
displace about 2 percent of Region V's natural gas demand and about 1
percent of the region's total energy needs during this time period.
Table 25 and Figure 15 show a shift in the utilization of shale oil
during 1988-1992. About 50 percent of these products will be pipelined to
Region V, while about 5 percent of the remaining shale oil products
marketed in Region VIII will be pipelined to Region X for utilization at
Mountain Home Air Force Base in Idaho. Another 5 percent of the remaining
quantity will be utilized at Hill Air Force Base in Utah (refer to Tables
26 through 28 for consumption by major consuming sectors). Coal-derived
liquids and LPG will be consumed in the respective production regions. SNG
produced in Region VI will be pipelined to Region IX for consumption (refer
to Table 29). The SNG produced in Region VIII will be consumed in that
region (about 50 percent) and the remaining SNG will be pipelined equally
to Regions V and VII (refer to Tables 26, 27, and 30). Of the expected
regional synfuel products' utilization patterns presented in Table 25, it
is shown that about 97 percent of Region VIII's middle distillate demand
will be provided by synfuel products, the split being 2 percent from
indirect coal liquids and 95 percent from shale oil.
The percentage of synfuel market penetration for this time period
compared to the last time period shows that SNG utilization in Region V
will be consistent. However, shale oil in Region VIII will almost triple
in both cases over the 1980-1987 time period. In addition, indirect coal
liquids and SNG will supply about 0.068 MMBPD and 0.075 MMBPD (0.0326 MMBPD
from indirect coal liquids) respectively of the demand for these products
76
-------
TABLE 22. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY REGIONS
SCENARIO II, 1980-1987 TINE PERIOD (IN NI1BPD)
PRODUCTS
NATURAL GAS
Current Consumption
Synfuels Contribu-
tion
LPG
Current Consumption
Synfuels Contribu-
tion
GASOLINE
Current Consumption
Synfuels Contribu-
tion
MIDDLE DISTILLATES
Current Consumption
Synfuels Contribu-
tion
RESIDUALS
Current Consumption
Synfuels Contribu-
tion
TOTAL
Current Consumption
Synfuels Contribu-
tion
EPA REGION
I
0.1266
0.0489
-
0.3592
0.3613
0.3628
1.2588
II
0.3834
0.0471
-
0.6190
0.6076
0.6016
2.2587
III
0.5507
0.0702
-
0.7957
0.4757
0.4130
2.3053
IV
0.7877
0.2505
-
1.3432
0.6659
0.5022
3.5495
V
1.9381
0.0420
0.3611
-
1.5265
0.8819
0.3005
5.0081
0.0420
VI
3.6962
0.2511
—
0.9523
0.5729
0.4032
5.8757
VII
0.6170
0.2070
-
0.4528
0.2193
0.0447
1 .5408
VIII
0.2995
0.0739
~
0.2708
0.0131
0.1516
O.OG70
0.0414
0.0069
0.8372
0.0770
IX
0.8697
0.0794
—
0.9698
0.4912
0.4590
2.8691
X
0.1939
0.0205
~
0.2726
0.2226
0.0636
0.7732
TOTAL
U.S.
9.463
0.042
1.410
~
7.562
0.013
4.650
0.057
3.192
0.007
26.277
0.119
-------
00
KEY
HBG — High Btu Gas
OS — Oil Shale
Figure 14. Synfuel Production and Utilization Regions - Scenario II 1930-1987
-------
TABLE 23. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO II--1980-1987 TIME PERIOD
REGION VIII (IN MI1BPD)
— — —
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.0984
0.0515
0.0185
0.0070
0.1684
0.0070
Commercial
0.0633
0.0057
0.0018
0.0001
0.0165
0.0062
0.0135
0.0023
0.1008
0.0086
Industrial
0.1121
0.0162
0.0145
0.0007
0.0238
0.0089
0.0222
0.0037
0.1888
0.0133
Transport-
ation
0.0071
0.0005
0.2545
0.0123
0.0907
0.0341
0.0043
0.0007
0.3571
0.0471
Electric
Utilities Total
i
i
0.0186 ' 0.2995
i
i
i
0.0739
! 0.2708
i _
0.0131
1
1
0.0021 0.1516
0.0008 0.0570
,
0.0014 0.0414
0.0002 0.0069
t
I
0.0221 0.8372
0.0010 0.077
Includes distillate fuel' oil, jet fuel, and kerosene
79
-------
TABLE 24. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS-SCENARIO II--1980-1987 TIME PERIOD
REGION V (IN I1MBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasol ine
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.8052
0.0174
0.1924
0.2685
1.2661
0.0174
Commercial
0.3841
0.0083
0.0214
0.0097
0.1122
0.0636
0.5910
0.0083
Industrial
0.6953
0.0151
0.1448
0.0306
0.0874
0.1229
1.0810
0.0151
Transport-
ation
0.0173
0.0004
0.0025
1.4862
0.3534
0.0236
1.8830
0.0004
Electric
Utilities
0.0362
0.0008
0.0604
Total
1.9381
0.0420
0.3611
1.5265
0.8819
:
0.0904
0.1870
0.0008
0.3005
5.0081
0.0420
'includes distillate fuel oil, jet fuel, and kerosene
80
-------
TABLE 25. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY EPA REGIONS
SCENARIO II — 1988-1992 TIME PERIOD (IN MMBPD)
PRODUCTS
NATURAL GAS
Current Consumption
Synfuels Contribu-
tion
LPG
Current Consumption
Synfuels Contribu-
tion
GASOLINE
Current Consumption
Synfuels Contribu-
tion
MIDDLE DISTILLATES
Current Consumption
Synfuels Contribu-
tion
RESIDUALS
Current Consumption
Synfuels Contribu-
tion
TOTAL
Current Consumption
Synfuels Contribu-
tion
EPA REGION
I
0.1266
0.0489
0.3592
0.3613
0.3628
1.2588
II
0.3834
0.0471
0.6190
0.6076
0.6016
2.2587
III
0.5507
0.0702
0.7957
0.4757
0.4130
2.3053
IV
0.7877
0.2505
1.3432
0.6659
0.5022
3.5495
V
1.9381
0.0420
0.3611
0.0059
1.5265
0.0349
0.8819
0.1704
0.3005
0.0285
5.0081
0.2817
VI
3.6962
0.2511
0.9523
0.5729
0.4032
5.8757
VII
0.6170
0.0420
0.2070
0.4528
0.2193
0.0447
1 . 5408
0.0420
VIII
0.2995
0.0746
0.0739
0.0001
0.2708
0.0977
0.1516
0.1466
0.0414
0.0183
0.8372
0.3373
IX
0.8697
0.0420
0.0794
0.9698
0.4912
0.4590
2.8691
0.0420
X
0.1939
0.0205
0.2726
0.0017
0.2226
0.0076
0.0636
0.0009
0.7732
0.0102
TOTAL
U.S.
9.463
0.201
1.410
0.006
7.562
0.134
4.650
0.325
3.192
0.048
26.277
0.714
-------
CO
HAWAII
KEY
HBG — High Blu Gas
OS — Oil Shale
CL(D — Coal Liquid — Indirect Liquefaction
CL(0) — Coal Liquid — Direct Liquefaction
Figure 15. Synfuel Production and Utilization Regions Scenario II - 7988-1992
-------
TABLE 26. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS-SCENARIO 11-1983-1992 TIME PERIOD,
REGION V (IN MMBPD)
Product
'.atural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
r. ,-
r o
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
direct Liquefaction
Oil Shale
"otal
Current Consumption
High-Btu Gasification
Indirect Liquefaction
T'irect Liquefaction
Oil Shale
SECTOR
Residential
0.8052
0.0174
0.1924
-
0.0031
0.2685
-
0.0057
0.0461
1.2661
0.0174
-
0.0088
0.0461
Commercial
0.3841
0.0083
0.0214
-
0.0003
0.0097
-
0.0002
0.1122
-
0.0024
0.0193
0.0636
-
0.0021
0.0039
0.5910
0.0083
-
0.0048
0.0234
Industrial
0.6953
0.0151
0.1448
0.0024
0.0306
-
0.0007
0.0874
-
0.0018
0.0150
0.1229
-
0.0041
0.0076
1.0810
0.0151
-
0.0083
0.0233
Transport-
ation
0.0173
0.0004
0.0025
-
0.0001
1.4862
-
0.0340
0.3534
-
0.0075
0.0608
0.0236
-
0.0008
0.0015
1 . 8830
0.0004
-
0.0084
0.0963
Electric
Utilities
0.0362
0.0008
0.0604
-
0.0013
0.0105
Total
1.9381
0.0420
0.3611
0.0059
1.5265
-
0.0349
0.8819
0.0187
0.1517
\
0.0904
0.3005
~ 1 ~
0.0030 ! 0.0100
0.0055
0.0185
0.1870 5.0081
0.0008
-
0.0420
-
0.0043 ! 0.0346
0.0160
0.2051
'includes distillate fuel oil, jet fuel, and kerosene
83
-------
TABLE 27. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS
BY REGIONS AND BY SECTORS—SCENARIO 11 — 1988-1992
TIME PERIOD REGION VIII (IN MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates9
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.0984
0.0138
0.0107
0.0515
0.00007
0.0185
0.0003
0.0176
0.1684
0.0245
0.00037
0.0176
Commercial
0.0633
0.0089
0.0069
0.0057
0.00001
0.0018
0.0005
0.0002
0.0165
0.00027
0.0157
0.0135
0.0002
0.0058
0.1008
0.0158
0.00098
0.0217
Industrial
0.1121
0.0157
0.0122
0.0162
0.00002
0.0145
0.0035
0.0018
0.0238
0.0004
0.0226
0.0222
0.0004
0.0094
0.1888
0.0279
0.00432
0.0338
Transport-
ation
0.0071
0.0010
0.0008
0.0005
0.0000
0.2545
0.0605
0.0312
0.0907
0.0015
0.0862
0.0043
0.00008
0.0018
0.3571
c, 0.0018
0.06208
0.1192
Electric
Utilities
0.0186
0.0026
0.0020
0.0021
0.00003
0.0020
0.0014
0.00002
0.0006
0.0221
0.0046
0.00005
0.0026
Total
0.2995
0.0420
0.0326
0.0739
0.0001
0.2708
0.0645
0.0332
0.1516
0.0025
0.1441
0.0414
0.0007
0.0176
0.8372
0.0746
0.0678
0.1949
Includes distillate fuel oil, jet fuel, and kerosene
84
-------
TABLE 28. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS
BY REGIONS AND BY SECTORS—SCENARIO 11 — 1988-1992 TIME
PERIOD REGION X (IN MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.0312
0.0094
0.0278
0.0010
0.0684
0.0010
Commercial
0.0279
0.0010
0.0029
0.00002
0.0269
0.0010
0.0096
0.0001
0.0683
0.00112
Industrial
0.1134
0.0098
0.0040
0.00002
0.0374
0.0012
0.0245
0.0003
0.1891
0.00152
Transport-
ation
0.0096
0.0003
0.2657
0.00166
0.1278
0.0043
0.0295
0.0005
0.4329
0.00646
Electric
Utilities
0.0118
Total
0.1939
0.0205
0.2726
0.0017
0.0027 ' 0.2226
0.0001 , 0.0760
! 0.0636
1
i
0.0009
i
!
0.0145
0.0001
j 0.7732
i
0.0102
Includes distillate fuel oil, jet fuel, and kerosene
85
-------
TABLE 29. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO 11 — 1988-1992 TIME PERIOD
REGION IX (IN MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasol ine
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.2795
0.0135
0.0283
0.0108
0.3186
0.0135
Commercial
0.1307
0.0063
0.0032
0.0097
0.0104
0.0076
0.1616
0.0063
Industrial
0.2625
0.0127
0.0469
0.0040
0.0599
0.0393
0.4126
0.0127
Transport-
ation
0.0145
0.0007
0.0010
0.9561
0.3983
0.1582
1.5281
0.0007
Electric
Utilities
0.1825
0.0088
0.0118
0.2539
0 . 4482
0.0088
Total
0.8697
0.0420
0.0794
0.9698
0.4912
0.4590
2.8691
0.0420
Includes distillate fuel oil, jet fuel, and kerosene
86
-------
TABLE 30. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS--SCENARIO 11—1988-1992 TIME PERIOD
REGION VII (IN IIMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.1868
0.0127
0.1212
0.0315
0.3395
0.0127
Commercial
0.1222
0.0083
0.0135
0.0050
0.0203
0.0077
0.1687
0.0083
Industrial
0.1885
0.0129
0.0711
0.0202
0.0311
0.0150
0.3259
0.0129
Transport-
ation
0.0392
0.0026
0.0012
0.4276
0.1251
0.0072
0.6003
0.0026
Electric
Utilities
0.0803
0.0055
Total
0.6170
0.0420
0.2070
0.4528
0.0113
0.2193
t
I
0.0148
0.1064
0.0055
0.0447
\
1 . 5408
0.0420
Includes distillate fuel oil, jet fuel, and kerosene
87
-------
in Region VIII as shown in Table 27. In Region V, direct coal liquids and
shale oil products (50 percent from Region VIII) will add about 0.035 MMBPD
and 0.2 MMBPD (Table 26). Region X will receive 0.01 MMBPD of transpor-
tation and heavy distillate products from Region VIII, which in turn will
satisfy about 2 percent of its gasoline, middle distillate, and residual
demand. About 1.3 percent of this region's total energy demand will be met
by synfuels (Table 28). Also during this period, 0.042 MMBPD of SNG will
be utilized in Regions IX and VII from production Regions VI and VIII,
respectively. This quantity of SNG will satisfy about 5 and 7 percent of
the regions' SNG demand and about 1.5 and 3 percent of their total energy
demand, respectively (Tables 29 and 30).
During 1993-2000, the utilization patterns are expected to remain the
same as in the last period. The differences will be an increase in the
quantities of synfuel products, along with the addition of products
produced in other regions. At this time, coal-derived liquids, SNG, and
LPG (Table 31) will be produced and utilized in Regions III and IV. The
major consuming sectors of these products are shown in Tables 32 and 33.
It is expected that about 24 percent of the LPG produced in Regions III,
IV, and V may be transported to Region VI for use by the petrochemical
industry (Tables 34 and 35). The small quantity produced in Region VIII is
expected to be consumed there, as shown in Table 36.
Compared to 1988-1992, synfuel market penetration during this time
period is likely to be identical for SNG utilization in Regions V, VII, and
IX. In addition, SNG production and utilization in Regions III and VIII
will add 0.084 MMBPD and an additional 0.0326 MMBPD more products to the
regions' SNG demand (Tables 32 and 36). The additional increase in SNG in
Region VIII will result from a doubling of indirect coal liquefaction
capacity. Region IV will add some 0.15 MMBPD of gasoline products from
indirect coal liquefaction and 0.066 MMBPD of products to displace LPG,
middle distillates, and residuals during this time (Table 33). The other
major differences in synfuels utilization by region and by sector for this
time period will be an increase in products produced; LPG consumption in
Region VI (refer to Table 35); and transportation of about 0.005 MMBPD of
coal-derived middle distillates to Region V for consumption because of the
excess capacity produced in Region VIII.
-------
00
HAWAII
KEY
HBO - High Blu Gas
OS — Oil Shale
CL(I) — Coal Liquid — Indirect Liquefaction
CL(D) — Coal Liquid — Direct Liquefaction
Figure 16. Synfuel Production and Utilization Regions Scenario II - 1993-2000
-------
TABLE 31. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PROJECTS BY EPA REGIONS
SCENARIO II -- 1993-2000 TIME PERIOD (IN I1MBPD)
PRODUCTS
NATURAL GAS
Current Consumption
Synfuels Contribu-
tion
LPG
Current Consumption
Synfuels Contribu-
tion
GASOLINE
Current Consumption
Synfuels Contribu-
tion
MIDDLE DISTILLATES
Current Consumption
Synfuels Contribu-
tion
RESIDUALS
Current Consumption
Synfuels Contribu-
tion
TOTAL
Current Consumption
Synfuels Contribu-
tion
EPA REGION
I
0.1266
0.0489
0.3592
0.3613
0.3628
1.2588
II
0.3834
0.0471
0.6190
0.6076
0.6016
2.2587
' III
0.5507
0.0840
0.0702
0.0045
0.7957
0.3000
0.4757
0.0187
0.4130
0.0100
2.3053
0.4172
IV
0.7877
0.2505
0.0090
1.3432
0.1500
0.6659
0.0374
0.5022
0.0200
3.5495
0.2164
V
1.9381
0.0420
0.3611
0.0202
1.5265
0.0366
0.8819
0.2389
0.3005
0.0594
5.0081
0.3971
VI
3.6962
0.2511
0.0106
0.9523
0.5729
0.4032
5.8757
0.0106
VII
0.6170
0.0420
0.2070
0.4528
0.2193
0.0447
1.5408
0.0420
VIII
0.2995
0.1072
0.0739
0.0002
0.2708
0.1638
0.1516
0.1511
0.0414
0.0198
0.8372
0.4421
IX
0.8697
0.0420
0.0794
0.9698
0.4912
0.4590
2.2691
0.0420
X
0.1939
0.0205
0.2726
0.0018
0.2226
0.0080
0.0636
0.0010
0.7732
0.0108
TOTAL
U.S.
9.463
0.317
1.410
0.0445
7.562
0.652
4.650
0.454
3.192
0.110
26.277
1 .578
vo
O
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TABLE 32. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO II--1993-2000 TIME PERIOD,
REGION III (flMBPD)
Product
'.atural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
IPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.2337
0.0356
0.0305
-
0.0020
0.1383
-
0.0054
0.4025
0.0356
-
0.0074
Commercial
0.1055
0.0161
0.0034
-
0.0002
0.0064
0.0024
0.0597
-
0.0024
0.0458
-
0.0011
0.2208
0.0161
0.0024
0.0037
Industrial
0.1885
0.0287
0.0356
-
0.00225
0.0033
0.0012
0.0586
-
0.0023
0.1049
-
0.0025
0.3909
0.0287
0.0012
0.00705
Transport-
ation
0.0214
0.0033
0.0007
0.00005
0.7860
0.2964
0.1839
-
0.0072
0.0490
-
0.0012
1.0410
0.0033
0.2964
0.00845
Electric
Utilities
0.0016
0.0003
Total
0.5507
0.0840
i
0.0702
;
0.0352
0.0045
0.7957
0.3000
0.4757
_ f _
0.0014
0.0187
0.2133 ; 0.4130
_ 1 _
0.0052 ; 0.0100
0.2501
0.0003
0.0066
2.3053
0.0840
0.3000
0.0332
Includes distillate fuel oil, jet fuel, and kerosene
91
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TABLE 33. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS-SCENARIO 11—1993-2000 TIME PERIOD,
REGION IV (III MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.1893
0.1567
_
0.0056
0.0779
0.0044
0.4239
-
0.0100
Commercial
0.1299
0.0174
_
0.0006
0.0100
0.0010
0.0392
-
0.0022
0.0290
-
0.0012
0.2255
-
0.0010
0.0040
Industrial
0.3184
0.0739
-
0.0027
0.0035
0.0005
0.1033
-
0.0058
0.1392
-
0.0055
0.6383
-
0.0005
0.0140
Transport-
ation
0.0438
0.0025
_
0.0001
1.3297
0.1485
0.3996
-
0.0224
0.0566
-
0.0023
1.8322
-
0.1485
0.0248
Electric
Utilities
0.1063
Total
0.7877
l
0.2505
_
! 0.0090
l
i 1.3432
! 0.1500
0.0459
0.0026
0.6659
-
0.0374
i
0.2774 0.5022
-
0.0110 0.0200
0.4296
-
3.5495
-
0.1500
0.0136 i 0.0664
'includes distillate fuel oil, jet fuel, and kerosene
92
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TABLE 34. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO 11—1993-2000 TIME PERIOD,
REGION V (IN MNBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.8052
0.0174
0.1924
0.0108
0.2685
0.0015
0.0227
0.0484
1.2661
0.0174
0.0015
0.0335
0.0484
Commercial
0.3841
0.0083
0.0214
0.0012
0.0097
0.0002
0.1122
0.0006
0.0095
0.0202
0.0636
0.0084
0.0041
0.5910
0.0083
0.0006
0.0191
0.0245
Industrial
0.6953
0.0151
0.1448
0.0081
0.0306
0.0007
0.0874
0.0005
0.0074
0.0158
0.1229
0.0164
0.0079
1.0810
0.0151
0.0005
0.0319
0.0244
Transport-
ation
0.0173
0.0004
0.0025
0.0001
1.4862
0.0357
0.3534
0.0020
0.0300
0.0638
0.0236
0.0032
0.0015
1.8830
0.0004
0.0020
0.0333
0.1010
Electric
Utilities
0.0362
0.0008
0.0604
0.0004
0.0052
0.0109
0.0904
0.0120
0.0059
0.1870
0.0008
0.0004
0.0172
0.0168
Total
1.9381
0.0420
0.3611
0.0202
1.5265
0.0366
0.8819
0.0050
0.0748
0.1591
0.3005
0.0400
0.0194
5.0081
0.0420
0.0050
0.1350
0.2151
Includes distillate fuel oil, jet fuel, and kerosene
93
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TABLE 35. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO 11 — 1993-2000 TIME PERIOD,
REGION VI (IN MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasol ine
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.2428
0.1329
0.0056
0.0217
0.4028
0.0056
Commercial
0.1641
0.0148
0.0006
0.0053
0.0574
0.0123
0.2539
0.0006
Industrial
2.0847
0.0935
0.0040
0.0033
0.1350
0.1057
2.4222
0.0040
Transport-
ation
0.1008
0.0099
0.0004
0.9437
0.3386
0.1801
1.5731
0.0004
Electric
Utilities
1.0984
='
0.0202
0.1051
1.2237
Total
3.6962
0.2511
0.0106
0.9523
0.5729
0.4032
5.8757
0.0106
alncludes distillate fuel oil, jet fuel, and kerosene
94
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TABLE 36. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO 11--1993-2000 TIME PERIOD,
REGION VIII (IN MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.0984
0.0138
0.0214
0.0515
0.00014
0.0185
0.0184
0.1684
0.0352
0.00014
0.0184
Commercial
0.0633
0.0089
0.0138
0.0057
0.00002
0.0018
0.0009
0.0002
0.0165
0.0165
0.0135
0.0004
0.0060
0.1008
0.0227
0.00132
0.0227
Industrial
0.1121
0.0157
0.0244
0.0162
0.00004
0.0145
0.0070
0.0019
0.0238
0.0237
0.0222
0.0008
0.0099
0.1888
0.0401
0.00784
0.0355
Transport-
ation
0.0071
0.0010
0.0016
0.0005
0.0000
0.2545
0.1211
0.0327
0.0907
0.0904
0.0043
0.00015
0.0019
0.3571
0.0026
0.12125
0.1250
Electric
Utilities
0.0186
0.0026
0.0040
Total
0.2995
0.0420
0.0652
0.0739
0.0002
0.2708
0.1290
0.0348
I
0.0021
0.0021
0.1516
0.1511
:
0.0014
0.00005
0.0006
0.0221
0.0066
0.00005
0.0027
0.0414
0.0014
0.0184
0.8372
0.1072
0.1306
0.2043
Includes distillate fuel oil, jet fuel, and kerosene
95
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TABLE 37. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO 11 — 1993-2000 TIME PERIOD,
REGION X (III MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasol ine
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.0312
0 . 0094
0.0278
0.0010
0.0684
0.0010
Commercial
0.0279
0.0010
0.0029
0.00002
0.0269
0.0010
0.0096
0.0001
0.0683
0.00112
Industrial
0.1134
0.0098
0.0040
0.00003
0.0374
0.0013
0.0245
0.0004
0.1891
0.00173
Transport-
ation
0.0096
0.0003
0.2657
0.00175
0.1278
0.0046
0.0295
0.0005
0.4329
0.00685
Electric
Utilities
0.0118
0.0027
0.0001
0.0145
0.0001
Total
0.1939
0.0205
0.2726
0.0018
0.2226
0.0080
0.0636
0.0010
0.7732
0.0108
'includes distillate fuel oil, jet fuel, and kerosene
96
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TABLE 38. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO 11 —1993-2000 TIME PERIOD,
REGION IV (IN MMBPD)
Product
Natural Gas
Current Consumption
High-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Gasoline
Current Consumption
Indirect Liquefaction
Oil Shale
Middle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
High-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
btCTUR
Residential
0.2795
0.0135
0.0283
0.0108
0.3186
0.0135
Commercial
0.1307
0.0063
0.0032
0.0097
0.0104
0.0076
0.1616
0.0063
Industrial
0.2625
0.0127
0.0469
0.0040
0.0599
0.0393
0.4126
0.0127
Transport-
ation
0.0145
0.0007
0.0010
0.9561
0.3983
0.1582
1.5281
0.0007
Electric
Utilities
0.1825
0.0088
0.0118
0.2539
0.4482
0.0088
Total
0.8697
0.0420
0.0794
0.9698
0.4912
0.4590
2.8691
0.0420
Includes distillate fuel oil, jet fuel, and kerosene
97
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TABLE 39. LIKELY UTILIZATION PATTERNS OF MAJOR SYNFUEL PRODUCTS BY
REGIONS AND BY SECTORS—SCENARIO 11 —1993-2000 TIME PERIOD,
REGION VII (IN Mi IBRD)
Product
Natural Gas
Current Consumption
^igh-Btu Gasification
Indirect Liquefaction
LPG
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Sascl ine
Current Consumption
Indirect Liquefaction
Oil Shale
Viddle Distillates3
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Residuals
Current Consumption
Indirect Liquefaction
Direct Liquefaction
Oil Shale
Total
Current Consumption
rign-Btu Gasification
Indirect Liquefaction
Direct Liquefaction
Oil Shale
SECTOR
Residential
0.1868
0.0127
0.1212
0.0315
0.3395
0.0127
Commercial
0.1222
0.0083
0.0135
0.0050
0.0203
0.0077
0.1687
0.0083
Industrial
0.1885
0.0129
0.0711
0.0202
0.0311
0.0150
0.3259
0.0129
Transport-
ation
0.0392
0.0026
0.0012
0.4276
0.1251
0.0072
0.6003
0.0026
Electric
Utilities
0.0803
0.0055
0.0113
0.0148
0.1064
0.0055
Tote1.
0.617C
0.042:
0.207C
0.452;
0.2192
0.0447
1 . 540fc
0.0423
a.
Includes distillate fuel oil, jet fuel, and kerosene
98
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SECTION 4
CHARACTERISTICS OF SYNFUEL PRODUCTS
This section reviews the limited data available on the characteristics
of synfuel products and by-products and on synfuel combustion products and
use properties. Where data are available on the corresponding
petroleum-based products, the synfuel products and their petroleum analogs
are compared. Relevant comments on the characteristics of synfuel products
as compared to petroleum products and the environmental significance of
their differences obtained through interviews with potential industrial
suppliers and users of synfuels are also summarized in this section.
Only limited characterization data on synfuel products are available;
however, there is also a lack of comparable data on petroleum products.
Surprisingly, in some cases there appears to be more data available on the
synfuel properties than on the characteristics of their petroleum analogs.
The limitations of the available data, and a review of some of the relevant
on-going and planned programs that are expected to generate additional
data, are presented in Section 7. Detailed data supporting the discussion
in this section are presented in Appendices A, E, F. and G.
4.1 PHYSICAL/CHEMICAL CHARACTERISTICS
4.1.1 Shale Oil Products
Most available data on the properties of shale oil products from
larger scale production operations have been collected on the DOD's
synthetic fuel development program, which included producing first 10,000
barrels, then 100,000 barrels, of crude shale oil at the Anvil Points,
Colorado, pilot plant (see Section E.I, Appendix E). The subsequent
refining, which was carried out at two different refineries, involved
producing gasoline, JP-4, JP-5, diesel fuel marine (DFM), and heavy fuel
oil to military specifications. The data collected on these products and
the data from other studies are presented in Appendix E. Based on analysis
of the data and the detailed information in Appendix E, the following
statements can be made about the characteristics of crude shale oil and
shale oil-derived gasoline, JP-4, JP-5, DFM, and residual fuels in
comparison with their petroleum-based analogs.
• As with crude petroleum oils, the characteristics of raw shale
oils vary depending on the source and the retorting method used,
and except for somewhat higher concentrations of certain elements
(for example, nitrogen and arsenic), which can be reduced by
appropriate refining techniques (for example, by
99
-------
hydretreating), shale oil composition falls within the
composition range for petroleum crudes.
• Based on the data collected during the refining of two shale oils
into products meeting military specifications, there appear to be
certain differences between the characteristics of shale oil
refined products and their petroleum-based analogs. However,
experience with refining petroleum crudes indicates that by
proper selection of the refining steps and conditions, crude
shale oils can be processed to obtain products with gross
characteristics similar to their petroleum-based analogs.
• Crude shale oil has a higher nitrogen and arsenic content than
petroleum crudes (1.8 to 2.17 weight percent versus 0.1 weight
percent, and 5 to 65 ppm versus 0.17 ppm, respectively). Unless
it is reduced by processing (for example, by hydrotreating), the
high nitrogen content can lead to problems in downstream refining
such as cracking, reforming and hydro- cracking. High
concentrations of organically bound nitrogen can also cause odor
and instability problems in the products and can increase NO
emissions during combustion. Removing of organic nitrogen by
hydrotreating and acid treating, however, improves the storage
stability characteristics of the product fuels, as determined by
gum and JFTOT measurements (see Section E.I.3 and Table E-7,
Appendix E).
• Mild hydrotreatment reduces nitrogen levels to below 100 ppm.
Hydrotreatment also significantly reduces arsenic content.
0 Crude shale oil contains significantly less vanadium than
petroleum crudes (0.1 to 0.55 ppm versus 4.4 ppm) (see Table E-2,
Appendix E). Because vanadium content directly influences the
conversion of sulfur to SO., during combustion, it can be
concluded that sulfate emissions from shale oil should be less
than conventional petroleum crudes.
t Most crude shale oils have consistently higher pour points than
most petroleum crudes (+50°F to +85°F versus -30°F to +57°F see
Table E-l, Appendix E). Distillation data also shows a lower
portion of the 650 F boiling fraction with shale oils (roughly 60
percent or more of the crude shale oil boils above 650 F compared
to 40 to 50 percent for three petroleum crudes tested see Table
E-l, Appendix E).
t Gasoline refined from crude shale oil will require reforming to
raise its octane number. However, as indicated by the data in
Table E-6 (Appendix E), refining causes a dramatic increase in
the aromatic content of shale oil gasoline (from 10.4 volume
percent to 50.1 volume percent). The presence of large amounts
of aromatics in gasoline can increase PNA formation during
combustion.
100
-------
• Nitrogen compounds in JP-5 refined from shale oil were implicated
in fuel stability problems. Removal by hydrotreatment and acid
clay treatment reduced nitrogen compounds to 0.5 ppmw and
produced fuels that met or exceeded the standards for storage
stability characteristics as measured by RD gum and JFTOT tests
(see Table E-7, Appendix E).
• The aromatic content of shale-derived JP-5 fuels is somewhat
higher than for typical petroleum derived JP-5, (21.5 to 25.8
volume percent versus 16 volume percent), but is within military
specification (25 volume percent maximum) (see Table E-7,
Appendix E).
• Diesel fuel marine (DFM) produced from refining of a shale oil
had high octane numbers (50.1) and hydrogen content (13 weight
percent), which indicate good combustion properties.
• Residual fuel oil from refining of a crude shale oil met all
military specifications (except pour point) for a low-sulfur,
high-power No. 6 fuel oil. The sulfur concentration was well
below specification for a typical No. 6 fuel oil (0.02 weight
percent versus 0.24 weight percent for No. 6 fuel oil and 3.5
weight percent maximum for military specification). The nitrogen
content was 0.44 weight percent (versus 0.23 weight percent for
No. 6 fuel oil), which is significantly less than that for the
crude shale oil (1.8 to 2.17 weight percent).
4.1.2 Direct Coal Liquefaction Products
As noted previously, of the three direct coal liquefaction processes
considered, only SRC II has been tested in a pilot plant; H-Coal and EDS
have not yet reached the pilot plant stage of development. Thus, the
characteristics of products and process streams from bench-scale and
pilot-scale units may not be representative of those from large-scale
plants, a major limitation that should be clearly understood in
interpreting the characterization data. It should also be noted that all
three liquefaction processes can be run in different modes to produce
different process oils. For example, H-Coal can be run in a boiler-fuel
mode to maximize residuum production or in a syncrude mode to produce a
wide range boiling fractions product. This section presents data for
H-Coal syncrude oil, EDS "raw" process liquid, and SRC II whole process
oil. Because coal type can affect product characteristics, where available
the type of coal used is also identified.
Detailed physical and chemical characterization data for the direct
liquefaction products are presented in Appendix E. The following is a
summary of the data and an interpretation of their significance.
• Syncrudes from the direct liquefaction processes have lower
viscosities and pour points than petroleum crudes. Kinematic
101
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viscosity measurements at 100 F have indicated values of 2.2 and
1.1 to 1.6 cst for SRC II whole process oil and H-Coal syncrude,
respectively (versus 6.14 and 18.9 cst for an Arabian light and
an Arabian heavy crude, respectively). A pour point value of
-80 F is reported for SRC II whole process oil (versus -30 F for
the two Arabian crudes). The lower viscosities and pour points
indicate better handling and transfer characteristics.
As with shale oil, direct liquefaction syncrudes have a high
nitrogen content (0.17 weight percent for H-Coal using low sulfur
coal to 0.85 weight percent for SRC II whole process oil versus
0.1 weight percent for crude oil). The nitrogen, however, can be
reduced to about 50 ppm by moderate hydrotreating and to less
than 1 ppm by severe hydrotreating.
The sulfur content of raw syncrudes (0.04 to 0.49 weight
percent)would classify them as low sulfur feed. The sulfur
content is reduced to about 20 ppm or less by hydrotreating.
SRC II whole process oil has an aromatic content of 55 volume
percent. Included in that value is almost 9 percent phenols.
The aromatic content is reduced to 49 percent by intermediate
severity hydrotreating and to 4 percent by severity
hydrotreating.
Naphtha from SRC II, H-Coal, and EDS contain 16.2, 18.6 and 25.3
volume percent aromatics and 3.2, 3.1 and 7.4 volume percent
phenols, respectively. Hydrotreatment appears to result in an
increase in total aromatic content and elimination of phenols.
The hydrotreated naphtha from the three processes contain 19 to
21 volume percent aromatics.
Naphtha from direct liquefaction processes has a low octane
number (40 to 70) and hence is not suitable for direct use as
gasoline. Hydrotreating/platforming or hydrocracking/platforming
produces gasoline stocks with octane numbers ranging from 91.5 to
99.8.
Gasoline or naphtha from direct liquefaction processes are
substantially less volatile than petroleum-derived leaded or
unleaded gasoline. The distillation end point for Q
petroleum-derived gasoline is 340 to 345 F versus 382 to 411 F
and 365 to 459 F for liquefaction naphtha and gasoline,
respectively.
Coal liquefaction naphtha can be processed to gasoline, having
gross compositions (percent aromatics, olefins, saturates, etc.)
similar to petroleum-derived gasoline.
The oil distillates from the EDS process are very low in nitrogen
and sulfur (0 ? *n n fi nnm *nrl ? tn 13Q nnm. resnpr.t.i vel vl.
Except for a
ar to petroleum-derived gasoline.
>il distillates from the EDS process are very low in nit
and sulfur (0.2 to 0,6 ppm and 2 to 139 ppm, respectively).
>t for a lower gravity (2.5 to 27.9 versus 30 API) and
102
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higher flash point (136 versus 100°F), the distillates meet the
specifications for No. 2 fuel oil.
• SRC II fuel oil (5.75:1 middle-to-heavy distillate ratio) is very
similar to No. 6 fuel oil in characteristics, except for lower
gravity (11 versus 25 API), heating value (17,081 versus 19,200
Btu/lb), pour point (-30 F versus 95 F), flash point (150 versus
200 F), and higher nitrogen content (1.02 versus 0.23 weight
percent).
• Jet and diesel fuels obtained from H-coal and SRC II syncrudes
meet the specifications for these products.
4.1.3 Indirect Coal Liquefaction Products
The indirect coal liquids addressed here include Fischer-Tropsch
gasoline, Mobil-M gasoline, and methanol. Most of the physical and
chemical properties reported for the two synthetic gasolines are estimates
made by Mobil Research and Development for commercial products. Despite
the fact that Fischer-Tropsch gasoline is produced commercially in South
Africa, detailed chemical analysis data are not available for this product,
as well as for Mobil-M gasoline and coal-derived methanol, which are not
produced on a commercial scale. The most environmentally significant
properties are reported below, but it should be kept in mind that these
products could actually be blended with petroleum gasolines. A more
detailed description of the indirect liquids is provided in Appendix E.
• Fischer-Tropsch gasoline is reported to be free of nitrogen and
sulfur, but no data are available on the extent to which oxygen
compounds are present.
• Estimates based on material balance calculations for a
commercial-scale Fischer-Tropsch production unit indicate that
the aromatics content of Fischer-Tropsch gasolines would be lower
than that of typical petroleum gasoline (17 versus 24 to 36
volume percent). The estimated saturate content (60 percent) is
similar to that of petroleum gasolines (56 to 59 percent), but
Fischer-Tropsch gasoline is estimated to contain signicantly more
olefins (20 percent) than typical petroleum gasoline (5 to 8
percent) (see Tables E-17 and E-21, Appendix E).
• The estimated Reid Vapor Pressure for Fischer-Tropsch gasoline
(10 psi) is within the range determined for petroleum gasolines
103
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marketed in the U.S. (7 to 15 psi) (see Section E.3.1, Appendix E),
The Fischer-Tropsch synthesis unit also generate a small stream
of oxygenates including alcohols, aldehdyes, and ketones. These
chemicals may be distributed commercially. (At the SASOL plant
in South Africa, the aldehydes are hydrogentated and nethanol is
used on site as make-up in the Rectisol gas cleaning unit;
ethanol , propanol, butanol, pentanol, acetone, MEK, and a higher
alcohol fraction are products distributed commercially (see
Section E.3.1.1, Appendix E).
Mobil-M gasoline is reported to be
of nitrogen, sulfur, and oxygen.
free of detectable quantities
The estimates of the amounts of saturates, olefins, and aromatics
in commercial Mobil-M gasoline (61, 7, and 33 weight percent) are
very similar to the amounts typical of petroleum gasolines in the
U.S. (56 to 59, 5 to 8, and 24 to 36 weight percent) (see Table
E-17 and E-27, Appendix E).
The estimated Reid Vapor Pressure for Mobil-M gasoline (9.0 psi)
is within the range determined for petroleum gasolines marketed
in the U.S. (7 to 15 psi) (see Table E-27 and Section E.3.1).
The concentration of benzene, a very volatile, hazardous
substance, in petroleum gasoline is approximately 0.3 volume
percent to 3.0 volume percent (Reference 36); no data are
available on the concentration of benzene in Fischer Tropsch
gasoline or Mobil-M gasoline.
In terms of gross characteristics, fuel-grade methanol from coal
conversion is not expected to be significantly different from
fuel-grade methanol derived from other sources
possible that certain hazardous substances may
coal-derived methanol. No analytical data are
support this assertion (Reference 36). Higher
and non-methane hydrocarbons will comprise less
, although it is
be present in
available to
alcohols, ethers
than one percent
of the crude methanol (see Table E-28, Appendix E). Water will
comprise about five percent (see Table E-28, Appendix E), but
this may vary if the distribution system introduces additional
water, because the very hygroscopic nature of methanol.
4.1.4 Coal Gasification Products
Most of the available data on
for products from Lurgi gasifiers.
discussion presented in Appendix E,
about the chemical characteristics
the chemical characteristics of SNG are
Based on analysis of the data and the
the following statements can be made
of SNG:
104
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As with natural gas, the principal component of high-Btu coal gas
is methane, typically about 98.4 percent by volume (dry). The
methane in natural gas ranges from 64.1 to 97.6 percent by
volume, depending on the source (see Appendix E, Section E.4.1,
and Table E-29).
Minor components of high-Btu coal gas and natural gas are
hydrogen, nitrogen, argon, carbon dioxide, and carbon monoxide.
Trace quantities of helium may also be present in both gases.
Specifications for natural gas currently require a CO level of
less than 1000 ppm. Concentrations of CO in high-Btu coal gas
are typically 60 ppm.
Sulfur-containing compounds, such as hydrogen sulfide, may be
present in both high-Btu coal gas and natural gas. Trace amounts
of carbonyl sulfide have been observed in high-Btu coal gas (see
Section E.4.1 and Table E-29, Appendix E). Gas purification and
upgrading processes remove nitrogen in SNG (References 37 and
38). Propyl mercaptan is often added to natural gas to provide
for odor detection in leaks.
Recent data from a pilot unit suggest that trace quantities of
metal carbonyls may be produced during SNG production in
methanation, in gasification, or by reaction of CO with metals in
system piping and other components (see Section E.4.1, Appendix
E). Metal carbonyls have not been detected in natural gas, and
would not be expected to be formed or remain in detectable
quantities in natural gas under natural geological conditions.
The concentration of metal carbonyls in SNG can be controlled by
selecting proper operating conditions. The rate of metal
carbonyl formation in SNG production is proportional to the total
gas pressure and CO partial pressure, and is inversely
proportional to temperature (References 38 and 39). Formation of
nickel carbonyl, Ni(CO) the one most readily formed, is favored
at temperatures below 275 C (Reference 40).
The recommended NIOSH permissible exposure limit for Ni(COK is
0.001 ppm (0.007 mg/cu m) (Reference 40). There are currently no
SNG product specifications for metal carbonyls.
Although quantitative data are currently unavailable, some trace
and minor elements* may be present in SNG and few volatile
ine definitions of the terms "trace" element and "minor" element are not
universal and are subject to interpretation. However, as applied to coal
and synfuel products it is generally held that trace elements are those
that occur in concentrations of less than 0.1 percent, and minor elements
are those that occur in concentrations of 0.1 percent to 1 percent by
weight (Reference 42).
105
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4
elements (such as As, Se, Te, Hg and F) are likely to be found in
natural gas. Some of these volatile elements are likely to be
present in higher levels in SNG than in natural gas, because of
their relative scarcity in natural environments and the
geological constraints associated with natural gas generation.
Detailed chemical characterization data for low-/medium-Btu coal gas
are provided in Section E.4.2, Appendix E, including Tables E-30, E-31 and
E-32. The following is a summary and analysis of the data.
• In general, the chemical composition of low-/medium-Btu gas is
highly variable, depending on such factors as coal type, gasifier
type, gasifier operating conditions, and extent of gas cleaning
performed.
• The major chemical components of low-Btu gas are: N,, CCL, CH
and 02 + Ar (46.8 percent, 26.3 percent, 15.4 perceht, 9.5
percent, 1.3 percent and 0.7 percent, respectively).
• Other constituents of low-Btu gas present at ppm levels or
greater are sulfur species (H?S, COS, S0?); C, to Cfi
hydrocarbons (CH C?Hfi, C?H., and variobs C^ to Cfi
isomers); nitrogen compounds (NH3 and HCN); and metal
carbonyls.
• A large number of trace and minor elements may also be present in
the low-/medium-Btu product gas, associated with particulate
matter and vapor phases (Al, Sb, As, Ba, Ce, Ga, etc.)
0 In addition to C-. to C/r hydrocarbons, a number of high molecular
weight complex organic compounds, such as dinitrotoluene and its
derivatives, PCB's, benzo(a)pyrene, and biphenyl, may be present
in low-Btu product gas. Many of these compounds are known or
suspected carcinogens.
• Product gas from a low-Btu gasification facility was shown to
contain 0.01 ppmv Ni(CO). and 0.004 ppmv Fe(CO)5 (Reference 41).
4.1.5 Summary of the Data Currently Available and Data Gaps from an
Environmental Assessment Standpoint
While more physical and chemical characterization data are available
for some synfuel products, for example, crude shale and gasoline derived
from shale oil, than for others, for example, coal-derived methanol, in
general the available data are very limited and cover only the gross
characteristics, for example, ultimate analysis or composition by classes
of compounds. Also, little characterization data are available for many of
the petroleum-based products that are currently in widespread use. In
general, the limited available data indicate that, in comparison with the
petroleum products, environmentally significant characteristics of synfuel
products relate to higher fuel-bound nitrogen and aromatic contents of
106
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liquid shale oil and coal liquefaction products. As will be discussed in
Section 4.2, higher levels of aromatics and fuel-bound nitrogen result in
an
increase in emissions of PNA's and NOV during combustion.
x
Although detailed characterization data are not available, synfuel products
would be expected to contain trace concentrations or minor amounts of
coal-derived or shale oil-derived hazardous substances.
4.2 COMBUSTION CHARACTERISTICS
4.2.1 Shale Oil Products
The DOD's synthetic fuel development program included a relatively
extensive evaluation of the combustion characteristics of the shale oil
products. Most of the work reported to date is based on the 10,000-barrel
sample (see Section E.I, Appendix E). In addition to the DOD efforts,
Southern California Edison Company (SCE) has studied the handling and
combustion (in a 45-MW utility boiler) of a separate lot of whole shale oil
for the Electric Power Research Institute (EPRI). Subscale and full-scale
tests have also been reported on the combustion of de-ashed and
de-sulfurized Paraho shale oil in gas turbine combustors. The combustion
test results for shale oil products are presented in Section F.I, Appendix
F, and are summarized below.
In the SCE evaluation tests, the crude shale oil was compared with the
low sulfur oil.* Because of California air quality control regulations,
only up to 50 percent of the burners were fueled with shale oil. The crude
shale oil had a somewhat higher nitrogen content (1.98 weight percent
versus 0.22 weight percent), sulfur (0.68 weight percent versus 0.27 weight
percent), and ash (0.22 weight percent versus 0.009 weight percent) and was
lower in heating values (HHV 18,195 versus 19,235 Btu/lb and LHV 17,145
versus 18,100 Btu/lb) than the low sulfur oil (see Table F-l, Appendix F).
The SCE study indicated:
• No significant fuel handling, fuel mixing, combustion
instability, smoke formation, or boiler operational problems
during burning of shale oil.
*Direct utilization of "unprocessed" crude shale oil as boiler feed would
have some economic merits and the SCE tests were aimed at evaluating such
use potential. The study, however, was not a comparison between crude
shale oil and petroleum crude.
107
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• High N0x emissions with the crude shale oil* (on the average 90
to 500 ppm higher during normal firing and 70 to 225 ppm higher
during off-stoichiometric burning) (see Table F-2, Appendix F).
• Increase in emission of particulates with the rise in the
percentage of crude shale oil in the feed (with 50 percent shale
oil, the mass emissions ranged from 0.15 to 0.12 Ib/M Btu
compared to 0.02 Ib/M Btu with low sulfur fuel alone (see Figure
F-l, Appendix F).
t With shale oil, emission of a higher fraction of larger particles
that should be more easily removable by the particulate control
devices (90 percent of the particles were larger than 20
micrometers (ym); estimates for oil-fired boilers range from 58 weight
percent below 3ym to 90 weight percent below 7 urn (see Section
F-l and Figure F-2, Appendix F).
• Lower emission of polynuclear aromatics (PNA) with the crude
shale oil (at 50 percent shale oil in the feed, the total PNA
emitted was 0.92 yg/m , which is within the range of PNA 3
emissions from petroleum oil burning plants — 0.1 to 9.24 yg/m -
see Table F-3, Appendix F).
The results of SCE studies are, in general, consistent with the
results of other studies in which the combustion characteristics of whole,
deashed, and desulfurized shale oils were compared with those of No. 2
petroleum distillates in a turbine combustor. These studies indicated only
10 to 20 ppm higher NO levels with the shale oil containing 0.33 weight
percent nitrogen. (The lowest NO emissions were observed at highest
exhaust temperature of about 2000 F). The smoke values were only slightly
above those of the No. 2 distillates over most of the range of exhaust
temperatures tested.
Only a limited number of combustion-related tests have been run with
gasoline, jet fuels, and DFM from shale oil (see Sections F.I.2, F.I.3, and
F.I.4, Appendix F). Except for slightly higher smoke and N0x emissions,
the shale-oil products have been found to exhibit combustion characteris-
tics very similar to those of their petroleum analogs. A flight test using
oil shale JP-4 in a T-39 was rated "normal" and no in-flight problems were
encountered. Corrosivity measurements have indicated no compatability
*It should be noted that lower NO emissions would have probably been
obtained if residual fuel oil from shale oil refining had been used instead
of crude shale oil for comparison with the low sulfur oil. As noted in
Section 4.1, residual shale fuel oil has a lower nitrogen content than the
crude shale oil (0.44 to 1.4 weight percent versus 1.8 to 2.17 weight
percent) (see Tables E-9 and E-2 in Appendix E).
108
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problem with the use of DFM in ship fuel systems. Tests with typical
diesel engines showed that combustion efficiency, CO, and THC were the same
as for petroleum DFM.
Although the combustion studies reported to date have not included
measurements of trace elements and sulfate emissions, chemical
characteristics of the shale oil fuels indicate that, except for certain
specific elements such as arsenic, mercury, and manganese, these emissions
should be comparable to, or lower than, those for petroleum based analogs.
Vanadium concentration in crude shale oil is significantly less than in
petroleum crudes; because SOo formation is directly related to vanadium
concentration, it can be concluded that SCL emissions under equivalent
conditions (excess (L and S) should be less for crude shale oil.
4.2.2 Direct Coal Liquefaction Products
The bulk of the combustion testing of direct liquefaction products has
been with SRC II-fuel-oil-type liquids. Various blends of SRC II liquids
(2:1 to 5.7:1 mixtures of middle-to-heavy distillates) have been combusted
in commercial boilers under a range of firing rate, flame configuration,
and excess air conditions. Fuel handling and corrosion characteristics and
emissions of NO , carbon monoxide, particulates, and PNA have been
monitored. The conditions used and the results obtained in some of the
more complete combustion tests are discussed in Section F.2, Appendix F,
and are summarized in Table 40.
Based on the results summarized in Table 40, except for a higher NO
emission, there appears to be no significant difference between the x
handling and combustion characteristics of SRC II fuel oil blends and
No. 6 fuel oil. The investigators have concluded that the excess NOX
emissions can be eliminated and the NO emissions reduced to less than the
0.5 Ib/M Btu EPA standard by proper burner design and combustion
modification. Although no data have been collected, based on the
composition data for the fuels trace element emissions for the SRC II fuels
should be comparable to those for petroleum fuels.
The handling and combustion characteristics of H-Coal liquids have
been evaluated only to a very limited extent. These evaluations have
primarily emphasized engineering aspects (atomization, coke formation,
combustion parameters); the environmental data collected in these tests
have been limited to emissions of NO and smoke. These studies, the
results of which are summarized in Tables 41, indicate that:
• H-Coal distillates, both raw and hydrotreated, appear to be
compatible with No. 2 fuel oil.
t The coke formation in a turbine combustor would be a problem for
raw H-Coal distillates, but is reduced dramatically by
hydrotreatment.
109
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TABLE 40. COMBUSTION TEST RESULTS FOR SRC II FUEL OILS
Investigator
SRC-11 Fuels Tested
Singh et al
(Reference 5;
Appendix F)
MD, HD. MD/HD blend,
3:1 N0.2/SRC-II blend,
1:1 No.Z/SRC-II blend
Bauserman
(Reference 8;
Appendix F)
Babcock and Mil cox
(Reference 13;
Appendix F)
5:1 MD/HD
5.75:1 MD/HD
KVB
(Reference 14;
Appendix F)
2:1 MD/HD
Equipment/test
Sub-scale
gas-turbine like
combustor
Full-scale combustor
used in Westlnghouse
30 to 90 MW engines;
187-h corrosion test
using various alloys
and SRC-11 solvent
wash
Package boiler
Ambient monitoring
44 MW field boiler
Results
• All fuels burned well
• no significant handling problem
• max excess NOX levels (with HD) 20 to
130 ppm above baseline
• Increase 1n smoke levels with decreasing hydro-
gen content & increasing aromaticitv of fuels
• decrease in % emissions of fuel-bound
nitrogen (FBN) with increase in fuel
FBN and outlet temperature.
t NOX emission for blend containing
9.83% FBN 30 to 120 ppm higher than No.2
distillates
• decrease in smoke value with increase
in exhaust temperature
t corrosion/deposition problems similar
to petroleum-derived products
• easy pumping/handling during test program
(replaced hydrocarbon seals with
teflon/viton seals as precausion)
• no benzene/phenol emitted, based on
ambient monitoring data
• NOX emissions for blend higher than for
No.2 and No.5
• no tendency to smoke despite higher
aromaticity
• lower particulate emission in comparision
with No.5 oil
• ash composition for blend similar to that
for No.5 oil except for Fe, Ca, Mg,
Cr, Mn and Sn which were higher.
• no major operation (burner optimization,
boiler deposits,etc.) problems in com-
parision with No.6 fuel oil
• NOX emissions about 70% higher than for
No.6 fuel oil
• lower particulate emissions compared to
No.6 fuel oil; emissions less than
proposed NSS of 0.03 Ib/M Btu
• PNA emissions for both,blend and No.6
less than 6 p/M3 (6x10- Ib/M Btu)
• tendency for Incomplete conbustion
comparable to No.6 fuel oil (CO levels
below 50 ppm)
*Sce Section F.2.T, Appendix F
* -SRC II Tu»T«.: MO - m^ddlo
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TABLE 41. COMBUSTION TEST RESULTS FOR H-COAL FUELS
Investigator
Fuel s
Equipment/test
Results
Mobil Research
(Reference 9,
Appendix F)
Singh, et. al.
(Reference 5,
Appendix F)
Sinqh, et. al.
(Reference 5,
Appendix F)
Raw and hydrotreated H-Coal distillate
No.2 fuel oil (reference)
Small combustion turbine
H-Coal distillates (210-480°F; 300-500°F;
and H-Coal atmospheric 450-650°F)
No.2 fuel oil (reference)
H-Coal distillate (210-480°F)
No.2 fuel oil (reference)
Sub-scale gas turbine
1 ike combustor
Full scale combustor
• Excellent atomization characteristics;
no deposit formation in fuel lines
• coke formation dependent on degree of
hydrotreating; negligible coke for-
mation with adequate hydrotreating
• severly hydrotreated H-Coal liquid
(10.5 and 11.7 wt.% H; FNB
0.2 wt.%) had lower NOx emissions
than NO.2 fuel oil (134 vs. 148 pptn)
• low CO emissions (31-41 ppm)
• 30 to 60 ppm more NOX emitted with
H-Coal fuels
• smoke level similar to No.2 fuel
• 20 ppm excess NOX emission with
H-Coal fuel (0.17 wt.% N) than
with No.2 fuel (0 wt.% N)
• lower smoke values except at exhaust
temperature above 1750°F
*See Section F.22, Appendix F.
-------
• N0x levels for severely hydretreated H-Coal distillates are
expected to be below NO levels for No. 2 fuel oil.
^
EDS fuels vary significantly in their handling and combustion
characteristics. Because of immiscibility with petroleum fuels and
differences in viscosity, they will require separate storage and transfer
lineSy Because of degradation upon exposure to air at higher temperatures
(100 F and above), nitrogen blanketing in storage tanks may be necessary
for at least some EDS fuels. Table 42 summarizes the combustion test
results for some EDS fuels. As noted in the table, the results indicate no
special problems (flame out, nozzle fouling, shutdown). These fuels burn
very cleanly and, except for higher NO emissions (which can be reduced by
hydrotreating), appear to have combustion characteristics similar to No. 2
petroleum fuel.
4.2.3 Indirect Liquefaction Products
No data on the emissions from combustion of Fischer-Tropsch or Mobil-M
gasoline are currently available. Sampling of uncontrolled emissions from
methanol-fueled automobiles and comparing the results with emissions from
gasoline-fueled engines (see Section F.3 and Reference 16 in Appendix F),
however, indicate that: (1) CO emissions are about the same but NO
emissions are lower; (2) hydrocarbon emissions are about the same and are
dominated by unburned methanol; (3) polynuclear aromatic emissions are
reduced to as little as one-tenth; (4) aldehydes, particularly
formaldehyde, are increased three to five fold; and (5) no lead or sulfur
are emitted.
4.2.4 Coal Gasification Products
Data on the combustion characteristics of low-Btu gas have been
obtained as part of an EPA-sponsored comprehensive assessment of low-Btu
gasification technology involving Source Test and Evaluation (STE) programs
at operating low-Btu gasification facilities. Analytical results of
testing at a facility using lignite coal are presented in Section F.4,
Appendix F. The data indicate that a wide variety of gaseous species can
be emitted as low-Btu gas combustion products (see Table F-9, Appendix F),
with the major components including N£ (77.8 + 5.2 percent), Oo/Ar (16.0 +
4.8 percent) and COo (5.4 ± 2.2 percent). S02, CSo, HCN and NR3 were
measured at 103 + 122, 2.8 + 5.8, 1.0 + 1.0 and 0.005 ppmv, respectively.
The chemical analyses also indicated that a wide variety of trace and minor
elements are emitted, both as particulate matter and as vapor (see Table
F-10, Appendix F). The elements detected at the highest concentrations,
that is, more than 120 pg/SCM, were barium, calcium, iron, magnesium,
potassium, silicon, sodium, and sulfur.
Aromatic compounds were also detected as constituents of the combusted
low-Btu gas. However, these compounds were generally simple ring systems
and included fewer nitrogenous compounds than the uncombusted product gas.
Benzo(a)anthracene v/as found to be present in the combusted gas at a
112
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TABLE 42. COMBUSTION TEST RESULTS FOR EDS COAL LIQUIDS
Investigator
Fuels
Equipment/test
Results
Quinlan
(Reference 18,
Appendix F)
Quinlan and
Segmond
(Reference 18,
Appendix F)
co
Singh , et al.
(Reference 5,
Appendix F)
400"I"°F (Illinois Coal)
FLEXICOKING liquid
blend containing
50-Hp package boiler
400-1000°F blend (containing No
FLEXICOKING liquid)
Reference petroleum fuels:
regular sulfur (2.2 wt.%S)
low sulfur (0.5 wt. S)
Raw and hydrotreated middle-distillate
coal liquid
No.2 fuel oil (reference)
1-gal/hr domestic oil
burner
EOS whole process liquid
EDS process without 650 F fraction
No.2 fuel oil (reference)
Sub-scale turbine-like
combustor
• No problems such as flame light-off,
nozzle fouling or shutdown encountered
0 coal liquids burned cleanly with
smoke levels equal to or less than
reference fuels at all levels of excess
air
• particulate emission levels were very
low for coal fuels (27 and 33 vs.
50 and 131 mg/SCM for reference fuels)
• NOX emissions from coal liquids higher
than for reference fuels (490 and 580
vs. 300 and 440 ppm for reference fuels)
• coal liquids burned cleanly
(same smoke number as reference
fuel at a given level of excess air)
• hydrotreated coal liquid interchangeable
with No.2 fuel
• NOX emissions from raw distillate higher
than with hydrotreated or reference
fuel
• smoke levels slightly higher than for
No.2 fuel
• NOX 60 to 75 ppm higher for the whole
process liquid (0.08 wt.%N) compared to
emissions for No.2 fuel.
*See Section F.2.3, Appendix F.
-------
concentration of 450 yg/SCM. Not present in the product gas were
benzo(a)pyrene, dibenzo(a,h)anthracene, and 7,12-dimethyl-
benzo(a)anthacene.
Although no actual data are currently available, the combustion
products of medium-Btu gas are expected to be similar to those for low-Btu
gas.
4.2.5 Summary Of The Data Currently Available And The Data Gaps From An
Environmental Assessment Standpoint
Based on the synfuel utilization scenarios developed in Sections 2 and
3, using synfuel products as fuel in combustion systems provides the
greatest potential for exposure. Thus, combustion emissions and their
potential impacts on air quality are of highest priority in any
comprehensive environmental assessment of synfuel products utilization.
Uhile more data are available on combustion characteristics of some
synfuel products, for example, shale oil and SRC II fuel oils, little or no
data are available on other synfuel products, for example, Mobil-M and
Fischer-Tropsch gasolines. In general, the limited combustion tests and
evaluations, that have been conducted have used batches of products
produced in pilot-plant units and have focused primarily on engineering
aspects of combustion (fuel handling, atomization, and corrosion
characteristics) with comparatively little emphasis on a comprehensive
environmental assessment of combustion emissions. For products for which
some environmental data have been reported, such data primarily relate to
emissions of conventional pollutants such as particulates and N0x. Except
for some recently generated data on the concentrations of trace and minor
elenents in flue gas from low-Btu gas combustion, environmental data, as
well as "information on various environmentally significant organic
constituents (for example, specific PNA's), are generally unavailable for
synfuel products. Also, the reported test results are largely for use as
fuels in boilers; other fuel uses, such as for use as gasoline in
automobiles, nave not been evaluated, or if evaluated, the results have not
yet Deen published.
Based on the limited combustion test data available for crude shale
oil and shale oil-derived gasoline, jet fuels, and DFM, these products
generally produce higher smoke and NO emissions than their petroleum
analogs. Higher NO emissions have also been observed in the combustion of
SRC II, EDS and H-c6al fuel oils. It has been asserted that the excess N0x
emissions from boilers can be reduced via combustion modifications.
4.3 BIOLOGICAL AND HEALTH EFFECTS CHARACTERISTICS
4.3.1 Shale Oi1 Products
Biological and health effects characteristics of shale oil and shale
oil products have been examined only to a very limited extent, using
samples from various experimental and pilot plant production and refining
114
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operations. Test results obtained to date indicate that, with the
exception of the crude shale oil from surface retorting, which has been
found to be more toxic than crude petroleum, there appear to be no
significant differences between petroleum and shale-derived products. The
following are the highlights of the reported data (see Section G-l,
Appendix G for details).
• Ames Salmonella tests conducted on crude surface retort shale
oil, crude in situ shale oil, and crude petroleum oils indicate
that shale oil is slightly more mutagenic than crude petroleum
oil. One set of tests with Salmonella typhimurium TA 98
indicated values of 0.59 to 0.65 revertants/yg for shale oil
versus 0.01 revertants/yg for two petroleum crudes and 114 ± 5
and 5430 ± 394 revertants/yg for benzo(a)pyrene and
2-aminoanthracene (two known carcinogens), respectively (see
Table G-2, Appendix G).
• Skin-painting studies with mice indicated that crude shale oil is
more potent than crude petroleum in inducing tumors, both in
terms of higher observed incidences and shorter latency periods
(see Table G-7, Appendix G).
• Mammalian cell culture studies (see Table G-5, Appendix G)
indicated higher cytotoxicity for shale oil than for petroleum
crudes (dose required to reduce number of colony producing cells
to 50 percent of control values was 40 to 200 yg/ml for shale oil
fractions versus 190 to 350 yg/ml for three petroleum crudes; the
corresponding values for three reference substances, cadmium
chloride, zinc chloride, and lead chloride were 0.3, 6.8 and 37
yg/ml, respectively). Shale oil also produced a higher
percentage (3 percent) of transformed cell colonies than crude
petroleum (0.2 to 0.4%) (See Table G-6, Appendix G).
• Acute toxicity of shale oil appears comparable to that of
petroleum crude (oral rat LD5Q of 9.22 g/kg versus >12 g/kg for
petroleum crudes.
• Eye irritation tests with rabbits and skin sensitization and
dermal irritation tests with guinea pigs indicated no significant
differences between petroleum and shale-derived JP-5 and DFM
fuels. Based on test results, all four fuels would be considered
non-irritants.
t Data similar to the above data for crude shale oil and shale oil
JP-5 and DFM are not currently available for other shale derived
products (e.g., residual fuel oil). Studies to generate some of
the needed data are currently underway.
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4.3.2 Direct Liquefaction Products
Although a considerable effort is currently underway to generate the
data needed to assess biological and health characteristics of direct coal
liquefaction products, at the present time very little health and
ecological effects data are available. The limited available data largely
relate to primary products (e.g., fuel oils) and do not cover all secondary
products (e.g., gasoline) or emissions associated with product end uses
(e.g., combustion). No health effects data have been reported for any of
the EDS products. The bulk of the available data discussed in this section
pertain to the SRC II products.
Table 43 summarizes the available health effects data for SRC II
products (available data cover only naphtha, light fuel oil, and heavy
distillates). These data indicate that based on Ames test and skin
painting studies naphthas from petroleum and SRC II are not significantly
different in their mutagenic or tumorigenic activity; SRC II appears to be
more acutely toxic via skin absorption. No health or ecological effects
tests have been conducted on gasolines produced from SRC II naphtha.
Neither SRC II middle distillate nor petroleum-derived No.2 fuel oil
appears to be mutagenic. SRC II middle distillate and petroleum middle
distillate (No.2 diesel oil) exhibit similar cytotoxicity, although the SRC
II product may be slightly more toxic. SRC II middle distillate is
somewhat more toxic than No. 2 diesel oil when orally administered to rats
and is reported to cause burns when it comes in contact with human skin, a
problem not associated with petroleum middle distillates.
Skin-painting tests indicate that both petroleum-derived industrial
fuel oils and SRC II-derived heavy distillates pose considerable skin
carcinogenicity hazards. The results of tests of mutagenicity,
cytotoxicity, and cell transformation indicate that the SRC II heavy
distillate is a very toxic substance.
The very limited health effects studies that have been conducted with
H-Coal products have been primarily with naphtha (from the syncrude mode of
operation) and middle distillate (from the fuel oil mode of operation). As
with petroleum-derived naphtha, H-Coal naphtha has been found to be non-
mutagenic (Ames Test). No other health effects data are available for
H-Coal naphtha. The relatively high phenols content of naphtha (3.1 volume
percent), however, indicate a higher degree of toxicity for H-Coal naphtha
as compared to petroleum products, which generally contain less than 1
volume percent phenols. Health effect data for H-Coal middle distillates
(fuel oil mode) are presented in Table 44. Comparable test results for
petroleum middle distillates are not available. As noted in Table 44, the
untreated middle distillate show moderate to high activity for
mutagenicity, tumor production, and cytoxicity. The potency is eliminated
or reduced by hydrotreating.
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TABLE 43. SUMMARY OF HEALTH EFFECTS DATA FOR SRC II PRODUCTS AND
(WHERE AVAILABLE) FOR PETROLEUM ANALOGS*
Test
Naphtha
Light Fuel Oil
Heavy Distillates
Ames Mutagenicity
Cytotoxicity (on cultured
mammalian cells)
Skin-painting
Acute and
toxicity
subchronic
Maternal and fetal
toxicity (rats)
Toxicity via skin
absorption
No mutagenic activity for
SRC-II (revertants/yg<0.01)
or petroleum naphtha
180 Vg/ml dose required to
produce a 50% reduction in
relative plating efficiency
(RPE); no comparative data
for petroleum analog
(RPEcn for crude petroleum
190-350 wg/ml)
As with petroleum naphtha
extreme low tumorogenic activity;
tumor incidence: 1/46 at 20 mg/
application after 456 days
(vs. 44/46 at 0.005 mg/applica-
tion for benzo(a)pyrene,
a known carcinogen)
Moderately toxic. Acute gavage
rat LDcQ: 2.3 g/K ' '
(5 days) gavage rat
0.96 g/Kg
rat LD<;/: 2.3 g/Kg; Subchronic
LD50:
No significant enhanced
toxicity to embryo or the
fetus (risk only slightly
higher than for the mother)
Unlike petroleum naphtha, shows
some acute effect at a high
dose levels (1.6
No measurable mutagenic activity
(revertants/ug <0.01);mutagenic
activity demonstrated for certain
petroleum distillates
RPE50: 200 yg/ml (vs. 250
Diesel oil No. 2 and 0.3 yg/m
cadmium chloride)
l for
for
More toxic than diesel oil (acute
rat LD50=3.75 g/Kg vs. 11.8 g/KrV,
sub acute gavage rat 1050=1.48 g/Kg
Same as for naphtha
Unlike the petroleum products,
can cause skin burns
Most mutagenic of the three SRC-II
products (a 40 ± 23 revertants/yg)
with an RPE50 of 30
most cytoxic of all synfuel pro-
ducts tested; very active in
effecting cell transformation
highly potent1'; 12S and 100S
tumor incidents after 456 days
at 0.23 and 2.3 mg/application,
respectively; 85% of tumors
malignant
LDjQ about the same as for
naphtha and light fuel oil
Same as for naphtha
*See Section G.2.1, Appendix G for details
tNo comparable data available for petroleum analog,
but industrial fuels oils have been shown to present considerable skin carcinogenic!ty hazard.
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TABLE 44. HEALTH EFFECTS TEST RESULTS FOR H-COAL FUEL OILS *
Test
Hydrotreatment
Raw Low Medium High
Mutagenicity (Ames)
Tumor Production
Cytotoxicity
Ht
M
M
H
N
M
H
N
M
N
N
L
*From Reference 15 in Appendix G
tH=high; L=low; M=medium; N=no response
4.3.3 Indirect Liquefaction Products
Carcinogenicity testing has been
(boiling point up to 204 C) from a Fi
a considerable amount of research on
performed. However, no other health
carried out on Fischer-Tropsch gasoli
Mobil-M gasoline. In the absence of
chemical composition of synthetic and
basis for judging their relative toxi
conclusions reached based on the cons
follows (see Section G.3, Appendix G)
conducted on a raw gasoline fraction
scher-Tropsch demonstration plant and
the toxic effects of methanol has been
or ecological effects tests have been
ne and no tests have been conducted on
actual test data, comparison of the
petroleum gasolines can provide a
cities. The test results and
ideration of compositions are as
Application of Fischer-Tropsch gasoline to the skin did not
induce skin cancer in mice or rabbits. Injection into the thigh
of rats did, however, caused carcinomas attributable to the
treatment in 2 of the 15 rats tested. Comparable tests have
apparently not been conducted for petroleum gasolines.
Examination of the data available on the gross characteristics of
Fischer-Tropsch and Mobil-M gasolines provides no reason to
believe that the two products will produce significantly
different health effects than petroleum gasoline.
Based on the gross characteristics data, the health effects
caused by exposure to coal-derived methanol are not expected to
be different from those of the methanol currently being used.
Widespread distribution of methanol as a motor fuel would,
however, result in increased exposure to the chemical. The
effects of chronic exposures to methanol are not known.
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4.3.4 Coal Gasification Products
Little data are currently available on the biological and health
effects of high-Btu coal gas. Although a number of high-Btu gasification
pilot plants have been in operation in the United States, the focus has
been on improving the gasification process, with little emphasis on health
and biological effects of product gases and waste streams.
Carbon monoxide, hydrogen sulfide and metal carbonyls, which are
present in high-Btu gas in trace amounts, are the principal toxic
constituents of SNG. Although the remaining constituents, methane, carbon
dioxide, nitrogen, argon, and hydrogen, are non-toxic, they can result in
asphyxia if their combined concentration exceeds 20 to 30 percent (volume)
in air. As indicated in Section 4.1.4, CO and HLS are also present in
natural gas, but metal carbonyls are not. The principal toxic effect of
carbon monoxide is also asphyxia by combining with hemoglobin and rendering
it incapable of carrying oxygen to the tissues. Because exposure to 1000
ppm or more is considered dangerous, current standards for pipeline quality
gas require the CO concentration to be below 1000 ppmv. High-Btu coal gas
would be upgraded to meet this criteria.
Hydrogen sulfide is an irritant at 20 ppm and an asphyxiant at higher
concentrations. Because a typical H^S concentration in high-Btu coal gas
is 0.2 ppmv, hydrogen sulfide does not pose a significant health hazard.
Toxic metal carbonyls, which are present in high-Btu coal gas in trace
amounts, are Ni(CO). and Fe(CO),-. Nickel carbonyl is extremely toxic, with
a lethal exposure in man of 30 ppm for 30 minutes. Chronic exposure is
associated with a high incidence of cancer of the respiratory tract and
nasal sinuses. Iron carbonyl is less toxic than nickel carbonyl.
Limited data are available on the biological and health effects
characteristics of low-/medium-Btu coal gas (see Section G.4.2, Appendix
G). The Department of Energy is currently sponsoring investigations of the
toxicological characteristics of product gas and effluents from low-Btu
gasifiers. Toxicological studies have also been conducted by EPA on
products of low-Btu combustion. EPA studies have involved testing of
particulates and resin extracts from combustion products from a
Wellman-Gal usha gasification plant in Fort Snelling, North Dakota
(Reference 26, Appendix G). The particulates and extracts were obtained
using a Source Assessment Sampling System (SASS), which consists of a
series of impingers, filters, and resins for the collection of particulates
and gaseous impurities. Cytotoxicity, acute toxicity, and Ames
mutagenicity tests on the extracts indicated no mutagenic activity at
concentrations below 10 Pi/test plate. (The extract was found to be
extremely toxic to the tester strains at concentrations greater than 10
i'1/test plate, which precluded carrying out the mutagenicity testing). The
extract was moderately cytotoxic to human lung fibroblast cells tested in
vitro and had an LDrn of greater than 10 g/kg, indicating low oral
toxicity.
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4.3.5 Summary of the Data Currently Aval 1 able and Data Gaps from an
Environmental Assessment Standpoint
While a considerable effort is underway to develop health effects data
on synfuel products, at the present time the limited available health
effects data generally address only a few of the primary synfuel products.
The data also do not cover many of the secondary synfuel products or
emissions associated with the use of the products as fuels. As with the
chemical characteristics, surprisingly little health effects data are
available for many of the petroleum products (which are currently in
widespread use) to provide a baseline for comparison of the relative safety
of the synfuel products. Samples that have been tested are from batches of
products from pilot-plant operations. Health effects characteristics of
the following products appear to be similar to those of their petroleum
analogs, and should not present special health effects concerns: shale
oil-derived jet fuels and DFM; SRC II middle distillate and naphtha;
severely hydrotreated H-Coal fuel oil and H-Coal naphtha; F-T gasoline; and
low-/medium-Btu gas. Crude shale oil, however, has been shown to be more
mutagenic, tumorigenic, and cytotoxic than petroleum crudes. Also, heavy
distillate from SRC II has been shown to present considerable skin
carcinogenicity, cytotoxicity, mutagenicity, and cell transformation
hazard.
4.4 RELEVANT COMMENTS FROM POTENTIAL MAJOR SYNFUEL SUPPLIERS AND USERS
Concurrent with their process development and optimization activities,
the developers of the synfuels are currently involved in a number of
programs aimed at characterizing synfuel products and at identifying and
developing refining procedures necessary to produce products comparable or
superior to currently used petroleum-based products. Anticipating a switch
to synfuel products, the designers and manufacturers of engines, boilers,
and other user's equipment, and other synfuel users (for example, the
petrochemical industry) have also been engaged in programs involving
assessment of combustion and use characteristics of synfuel products in
order to identify necessary modifications to equipment and handling
systems. Many of these programs are on-going and because they are
generally considered company proprietary, the results are not publicly
available. To obtain insights into the thinking of potential synfuel
suppliers and users, interviews were conducted in this study with three
major potential suppliers (Exxon, Tosco and Shell), a petroleum industry
trade organization (American Petroleum Institute), three potential major
users (General Motors, a major chemical company and Department of the
Navy) and Electric Power Research Institute (representing the utility
industry's interests). Details of the interviews are presented in
Appendix A. Those portions of the acquired information that relate to the
characteristics of synfuels in comparison to petroleum products and the
environmental significance of such differences are summarized in Tables 45
and 46. It should be emphasized that the data presented here and in
Appendix A represent the views expressed by the interviewees. Some of the
assertions and statements made, which are reproduced here without
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TABLE 45. SUMMARY OF COMMENTS FROM SYNFUELS SUPPLIERS ON THE
RELATIVE CHARACTERISTICS OF SYNFUELS AND PETROLEUM
PRODUCTS
Company/Organization
Comments
EXXON
TOSCO
Shale oil
• Raw shale oil is equivalent to low-grade petroleum
crude and can be processed to a premium feed for
refineries
• Refinery processes are continueously modified to
handle different crudes and can readily handle shale
oil which is equivalent to a heavy crude
• Shale oil will produce essentially the same products
as currently produced from petroleum (in terms of
ASTM fuel specs).
Coal liquids
• Direct liquefaction products are highly aromatic:
upgrading via severe hydrotreating/hydrocracking
necessary to produce petroleum-like products
• Naphtha from direct liquefaction processes is easily
converted to prime mogas base stock; EDS is being
refined to yield all naphtha and distillates
• Products from indirect coal liquefaction are very
similar to petroleum based products
• Heavy oils will contain polynuclear aromatic
substances (PNA's). Handling and burning of heavy
oils may be an issue and long term health effects
of combustion products not known. Some testing
would be necessary
• Except for some effect on the optic nerve, methanol
is more benign than gasoline. Methanol spilled in
water is less of a problem than gasoline.
There are no composition unique to oil shale
compared to petroleum; crude petroleum has a range
of composition that brackets crude shale oil
The higher nitrogen and arsenic contents of shale
oil can be removed by hydrotreating and use of
catalyst guard beds, respectively
Products (e.g., gasoline) from shale oil will be
produced to specifications as are petroleum based
products
Toxicity testing indicates the same or a lesser
carcinogenicity potential for shale oil than for
conventional crude or industrial fuel
As far as polycyclic aromatic hydrocarbons (PAH's)
are concerned, no difference between shale oil and
crude oil has been found.
121
(continued)
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TABLE 45. (CONTINUED)
Company/Organization
Comments
API
• Comsumers will see no difference between synfuels and
traditional petroleum; after refining and processing
all products will meet current specifications; such
things as aromatics, trace elements, etc. will be
controlled
• All petroleum crudes are different and processing is
tailored for each crude. Processing and refining of
synfuels will be very analogus to conventional
petroleum processing problems
• Environmental risks with synfuels will be the same as
for current products
t When comparing toxicity, synfuels products should be
compared with their petroleum analogs; relative and
not absolute toxicity and impacts should be considered.
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TABLE 46. SUMMARY OF COMMENTS FROM POTENTIAL SYNFUEL USERS ON THE
RELATIVE CHARACTERISTICS OF SYNFUELS AND PETROLEUM
PRODUCTS
Company/Organization
Comments
General Motors
A Major Chemical Company
ro
c*>
Department of the Navy
EPRI
• For the most part, the users will not Identify differences between petroleum products and synfuels
• Refining and processing will be the key to acceptable use of synfuels. Suppliers can process synfuel
feedstocks to yield any specified products; the extent of processing 1s a matter of economics
• Optimum utilization of synfuels necessitates examination of possible engine modifications to take
advantage of certain synfuel properties (or to reduce processing required); e.g., higher
compression engines should efficiently handle hlqhlv aromatic coal liquids. GM Is Involved 1n R&D work to
take advantage of certain synfuel properties and Is looking at use of less refined products.
• Major characteristics of suntuels which, unless corrected, may Impact synfuel utilization are
high arsenic content of whole oil products (Impacting catalytic after burners In cars), high
fuel-bound nitrogen content of shale oil products (yielding NOX emissions 1n excess of the standard
1.0 g/ml), high aromatic content of coal-derived products which may result In generation of PNA's
In excess of what can be handled by existing catalytic converters and high evaporative emissions
from use of alcohol as gasoline additive.
• Synthetic LPG will be similar to the LPG produced from natural gas; acid qas purification of med1um-Btu gas
will take out trace contaminants.
• Some coal liquefaction products may contain higher amounts of PNA and substituted phenols. This 1s, however,
also the current situation with residuals from pyrolysls of heavy liquids for chemical production operations.
• Extensive chemical alterations which take place In chemical operations would also affect chemical
alteration of any hazardous constituents
• Characteristics of synfuels are under Investigation; some differences (e.g., higher nitrogen content
In shale oil products) have been noted
• Because of current heavy Investment In equipment, at least In the next 10-20 years new fuels should
meet specifications for use In existing equipment
• Existing specifications must be modified or new specifications must be drawn up to take care of
any problems associated with new fuels (e.g., toxldty or health effects considerations, high
nitrogen content which can cause gumming, or extensive hydrotreatlng which may destroy product
lubricity)
• In evaluating health effects of synfuels, petroleum products should be used as a baseline;
emphasis should be on areas which create "worse" problems than petroleum products.
• Distilled shale oil products will look much like petroleum products
• Some form of combustion modification will be needed with liquid synfuels to reduce NOX emissions
• Potential health effect risks associated with handling and end uses of synfuels 1s not known.
-------
alteration, are not supported by the data presented in this report. These
assertions and statements may have been based on an inadequate data base or
on results of the studies conducted by the industry that were not available
to this study.
As noted in Table 45, the suppliers generally take the position that
there will be no discernible or significant differences between the refined
liquid products produced from synfuels and the comparable products from
petroleum or natural gas. These synfuels products will be produced to
specifications using conventional, well-known processes. This, then,
naturally leads to a concensus among suppliers that no additional or
special concerns are warranted. In the case of shale oil, for example, it
is indicated that there are no compositions unique to shale oil compared to
petroleum and that the physical and chemical characteristics of synfuel
products will be essentially the same as those for refined petroleum
products. (The products are processed to specifications and the users
will identify no significant differences). It is also pointed out that
crude petroleum, as derived from various locations, exhibits a range of
compositions that brackets oil shale. Unacceptable quantities of nitrogen,
sulfur, and arsenic are removed by upgrading, hydrotreating, or other
refining steps. This additional processing or upgrading is a matter of
economics. The trend in the U.S. is to upgrade the bottom of the barrel,
and the processing and refining of synfuels will be very analogous to
conventional petroleum processing.
While expecting the suppliers to produce synfuel products to
specifications, the potential synfuel users indicate an uncertainty
regarding the adequacy of current specifications to guarantee performance
and environmental acceptability. For example, severe hydrotreating may
destroy or alter certain characteristics of fuels, such as lubricity, so
that trade-offs in processing to remove contaminants versus preservation of
performance may limit the degree to which additional processing is used.
The users generally see a need for some modification of end use devices.
Engines and combustors must be modified to use the synfuels efficiently and
cleanly. In the utilization of both transportation and boiler fuels,
emissions from combustion are likely to be the primary constraint.
In general, the suppliers expect to produce most products to
specifications so that no environmental problems over and above those
present in the marketing of conventional products should be encountered.
Both suppliers and users indicate that in reviewing product characteristics
for regulatory purposes, synfuel products must be compared with their
petroleum analogs and that the relative and not the absolute impacts should
be of concern. If the existing product specifications do not adequately
take into account health effect concerns, the specifications should be
modified or more appropriate ones should be developed.
The users and suppliers interviewed are generally involved in tests of
various synfuel products for both performance and potential environmental
impacts (see Appendix A). These tests are expected to determine the degree
124
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of additional processing required and the acceptability of synfuel
products. For example, Exxon Company, the developer of the EDS process, is
involved in test and evaluation (including combustion and toxicology
testing) of EDS products. DOE, API, and the Department of the Navy are
sponsoring toxicological testing of several shale oil products. General
Motor's planned synfuel evaluation testing program will begin with fuel
characterization and performance assessment in a single-cylinder engine;
these efforts will be followed by the evaluation of possible engine
modifications for more efficient fuel utilization and full-scale
multi-cylinder and actual automobile engine testing.
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SECTION 5
ENVIRONMENTAL ANALYSIS OF SYNFUEL UTILIZATION AND POTENTIAL
AREAS OF MAJOR ENVIRONMENTAL CONCERN
This section reviews the potential areas of environmental concern in
synfuel utilization based on the data presented in Section 4 and, where
data are unavailable, on estimated or anticipated characteristics of such
products. The known and estimated environmental significance of product
properties a^e then related to the product utilization scenarios developed
in Sections 2 and 3, and potential environmental areas requirino more
immediate attention are highlighted. In general, the environmental
analysis is in "relative" rather than "absolute" terms, in that properties
and use impacts of synfuel products are reviewed in comparison with those
of their petroleum analogs. Because the synfuel processes are largely in
the evolutionary stages and considerable efforts are underway to
characterize synfuel products, the analysis and the environmental
priorities identified in Section 6 should be viewed as preliminary and
hence subject to revision as the processes are further refined toward
commercialization and new data become available.
5.1 SIGNIFICANCE OF REPORTED SYNFUEL PRODUCTS CHARACTERISTICS
Table 47 summarizes the reported known differences in chemical,
combustion, and health effect characteristics of synfuel products and their
petroleum analogs, based on the data presented in Section 4. The primary
differences are the synfuel product's higher content of aromatics and fuel-
bound nitrogen (FBN) and greater emissions of NOx during combustion.
Although no actual test data on synfuel products are currently available,
high concentrations of aromatics in fuels have been shown to enhance
production of PNA' s during combustion. The specific substances that
comprise the aromatic and the FBN fractions also determine the
environmental hazards associated with products. No actual data have been
reported on the composition of aromatic or FBN fractions in various synfuel
products (or their petroleum counterparts). In the case of fuels, high
aromaticity has been generally implicated in an increase in smoke
production; the limited combustion data that are currently available,
however, do not indicate higher smoke levels with all aromatic synfuels
(see Tables 40, 41, and 42). High FBN content can raise the level of NOx
emissions; the excess NOx emissions with synfuels are believed to be
correctable by combustion modifications. The nitrogen content of the
synfuels (and the high arsenic content of the crude shale oil) can also be
lowered to meet appropriate fuel specifications by the use of certain
refining processes (for example, hydrotreating for reduction of FBN).
Another example of controlling undesirable product characteristics via
126
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TABLE 47. REPORTED KNOWN DIFFERENCES IN CHEMICAL, COMBUSTION, AND HEALTH
EFFECTS CHARACTERISTICS OF SYNFUEL PRODUCTS AND THEIR
PETROLEUM ANALOGS
Product
Chemical Characteristics
Combustion Characteristics
Health Effects Characterisecs
ro
-------
TABLE 47. (CONTINUED)
ro
oo
Product
Direct Liquefaction, Contd.
H-Coal naphtha
EOS naphtha
SRC II gasoline
H-Coal gasoline
EDS gasoline
|ndirect Liquefaction
FT gasoline
FT by-product
chemical
Mobile-M gasolIne
Methanol
Gasi fIcatlon
SNG
Low/medium Btu gas
Gasi fier tars, oils,
phenols
Chemical Characteristics
Higher nitrogen, aromatics
Higher nitrogen, aroiiidtics
Higher aromatics
Higher dronidtics
Higher aromatics
Lower aromatics; N and S nil
(Gross characteristics similar
to petroleum gasoline)
Trdces of metal carbonyls and
higher CO
(Composition varies with coal
type and gasifier design/
operation)
(Composition varies with coal
and gasifier types, highly
aromatic materials)
Combustion Characteristics
N/A
Higher aldehyde emissions
(Emissions of a wide range of
trace and minor elements and
heterocycllc organlcs)
Health Effects Characteristics
Non-mutagenlc
Non-carcinogenic
Affects optic nerve
Non-mutagenic,moderately
cytotoxic
-------
process control (or in-plant treatment) is the elimination of traces of
carbon monoxide and nickel carbonyl in SNG via proper operation of the
methanator (Reference 37) or use of activated carbon adsorption.
Table 47 identifies fuel oils from coal liquefaction processes and
crude shale oil as highly hazardous because of their established mutagenic,
tumorigenic, and cytotoxic properties. These hazardous properties, which
are characteristic of high boiling and tarry coal and petroleum materials,
are caused by the presence of substances such as polycyclic aromatic
hydrocarbons, hetero- and carbonyl-polycyclic compounds, aromatic amines
and certain inorganics (for example, arsenic in crude shale oil) (Reference
43). The environmental concerns in the use of these substances relate
primarily to the potential exposure of workers involved in handling and
processing the raw products and in the management of sludges from storage
tanks or spill clean-up operations. Workers' exposures can be reduced by
use of protective clothing; enforcement of appropriate safety and
industrial hygiene programs to reduce potential for skin contact; and
proper design and operation of processing, storage, and transportation
equipment to ensure adequate containment and to minimize the potential for
accidental spills.
5.2 ESTIMATED/ANTICIPATED CHARACTERISTICS OF VARIOUS SYNFUEL PRODUCTS
AND ASSOCIATED ENVIRONMENTAL CONCERNS
In the absence of actual data, and for use in planning and
prioritizing regulatory and research and development activities, estimates
have been made in this section of the characteristics of synfuel products
that would be expected to be of major potential environmental consequence,
based on the properties of input and starting raw materials and process
engineering considerations. Based on these estimates, the potential areas
of environmental concern for various anticipated uses are identified. The
analysis presented in this section is based on the premise that even though
in many cases the petroleum and synfuels products may present similar types
of hazards, the hazard potential, or the degree of risk, could be greater
for the synfuel products.
The estimated product characteristics and the analysis of the
environmental consequences are summarized in Tables 48, 49, and 50 for
shale oil products, coal liquefaction products, and coal gas products,
respectively. (The applicable controls and regulatory considerations will
be discussed in Section 5.3). The expected characteristics of
environmental concern relate to the known or potential presence of toxic
substances (including carcinogenic compounds associated with crude shale
oil and heavy distillates from coal liquefaction and hazardous aromatics),
fuel-bound nitrogen, volatile components and minor and trace elements.
Potential environmental concerns for the anticipated product uses generally
fall into three categories: occupational exposure, public exposure and
general environmental pollution. The occupational hazards affect workers
manufacturing and using the products and personnel involved in facility
maintenance and product distribution services. Public exposure primaril>
129
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TABLE 48. SOURCES AND NATURE OF ENVIRONMENTAL CONCERNS IN THE UTILIZATION OF
SHALE OIL PRODUCTS
Product
Major Anticipated
Uses
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Regulatory
Considerations
Raw Crude
Boiler fuel
Co
o
Hydrotreated
Crude
Refinery feed-
stock
Toxic substances including
carcinogenic compounds
associated with high boiling
point organics and the in-
organics; trace elements,
fuel-bound nitrogen (FBN);
volatile components such as
lower molecular weight
hydrocarbons
Same as for crude oil, ex-
cept for significantly
lower concentrations, de-
pending on the degree
of hydrotreating
Exposure of workers to
product during handling
and transport; air, water
and soil contamination as
a result of spills; and
leaks. Disposal of
sludges from storage
tanks, spill clean-ups
and air/water pollution
associated with combus-
tion; disposal of
combustion ashes; emis-
sions of NO,., trace
elements and specific
PNA's during combus-
tion
Exposure of workers to
product during handling
and transport; air,
water and soil contam-
ination resulting from
spills and leaks;
disposal of sludges
from storage tanks
and spil1 clean-ups
Design, operation and maintenance of
storage tanks, pipelines, pumps and
other equipment to provide for
maximum containment and minimum
potential for spills and leaks.
Minimize worker exposure (skin) via use
of protective clothing, enforcement of
appropriate industrial hygiene and
operating practices; development of spill
control contingency programs; employ-
ment of combustion modification to re-
duce air emissions; development and
enforcement of appropriate emission
standards; regulation of transportation,
storage and disposal of sludges from
storage tanks and spill clean-ups and
combustion ashes and sludges
Design, operation and maintenance of
storage tanks, pipelines, pumps and
other equipment to provide for maximum
containment; minimize potential for
spills and leaks; minimize worker
exposure (skin) via use of protective
clothing and enforcement of appropriate
industrial hygiene and operation
practices; development of spill
control contingency programs;
regulation of transportation.
sto'-age and disposal of sludges from
storage tanks and spill clean-ups,
incorporation of environmental
considerations in specifications
for shale oil refinery feedstocks
(continued)
-------
TABLE 48. (CONTINUED)
Product
Major Anticipated
Uses
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Regulatory
Considerations
Gasoline
Motor fuel
Jet fuel
Jet fuel
Can be high in aromatics
(depending on the refining
method used) which may
include toxic substances
such as benzene.* PNA's
and certain trace ele-
ments; volatile components
such as lower molecular
weight hydrocarbons
High aromatics; hazardous
trace elements such as
arsenic; volatile com-
ponents such as lower
molecular weight
hydrocarbons
Inhalation of volatile
matter by service
station attendants and
motorists during fuel
transfer product
handling; potential for
air (and water) pollu-
tion resulting from
spills and leaks and
evaporative emissions
from storage tanks; poten-
tial adverse effects of
combustion products on
catalytic converters
(e.g., pensioning of
catalyst with arsenic
and excessive amounts of
PNA's); disposal of
sludges from spills and
storage tanks and
poisoned/used catalysts;
emission of hazardous
combustion products
such as PNA's and trace
elements
Evaporative emissions
during handling, trans-
port, storage and
transfer; air, water
and soil contamination
resulting from spills:
disposal of sludges
from storage tanks and
spill clean-ups;
emissions of hazardous
combustion products and
NOX
Proper design and operation
of sources of evaporative emissions
(transfer lines/equipment, storage
facilities and spills/leaks); develop-
ment of spill control contingency
programs ; development and enforcement
of appropriate emissions standards;
regulation of transportation, storage
and disposal of sludges from storage
tanks and spill clean-ups; incorporation
of environmental (Including emissions)
considerations in specifications
for the shale-oil product
Same as Motor fuel
^Petroleum gasoline contains 0.3 to 3 Vol.? benzene (Reference 36)
(continued)
-------
TABLE 48. (CONTINUED)
Major Anticipated
Uses
Product
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Reguldtory
Considerations
OFM
Marine fuels
Residue
Boiler fuel
CO
f\>
High aromatics can imply
presence of toxic phenolics;
the higher boiling point
fraction and residue may
contain carcinogenic
organics; high content of
FBN
High aromatics can imply
presence of toxic phenolics;
being a high boil ing
fraction, can contain
carcinogenic substances;
high content of FBN
and trace/minor elements
Exposure of workers to
products and some evapor-
ative emissions during
handling and transport;
air, water and soil
contamination resulting
from spi1 Is,; disposal
of sludge from storage
tanks and spill
clean-ups; emissions of
hazardous combustion
products
Exposure of workers to
product during handling
and transport; air,
water and soil contam-
ination resulting from
spills; disposal of
sludge from
spill clean-ups and
air/water pollution
control sludges and ash
associated with
combustion; emissions
of hazardous combustion
products
Same as for Jet fuels, plus minimize
worker exposure via use of protective
clothing, appropriate industrial
hygiene and operating practices;
development of spill control contin-
gency [)lan
Same as for untreated crude shale oil
-------
TABLE 49. SOURCES AND NATURE OF ENVIRONMENTAL CONCERNS IN THE UTILIZATION
OF COAL LIQUEFACTION PRODUCTS
Product
Major Anticipated
Uses
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Regulatory
Considerations
Coal liquids
Gasoline
Engine/appliance
fuel
CJ
CO
Naphtha
Petrochemical
feedstocks
For direct liquefaction
gasoline, high contents
of aromatlcs, nitrogen
and volatile toxic
substances such as
benzene and toluene
For direct liquefaction
naphtha, high content
of nitrogen and volatile
aromatlcs, Including
toxic phenols and
benzene
Inhalation of volatile
matter by service
station attendants and
motorists during fuel
transfer and product
handling; potential
for air (and water)
pollution resulting
from spills and leaks
and evaporative
emissions from
storage tanks; poten-
lal adverse effects
of combustion pro-
ducts on catalytic
converters; disposal
of sludges from
spills and storage
tanks and poisoned/
used catalysts; emis-
sion of hazardous
combustion products
Evaporative emissions
during handling, trans-
port, storage and
transfer; air, water
and soil contamination
resulting from spills;
disposal of sludges
from storage tanks and
spill clean-ups
Strict regulation of desian and opera-
tion of sources of evaporative emissions
(transfer lines/equipment, storage
facilities and spills/leaks); develop-
ment of spill control contingency
programs; development and enforcement
of appropriate emissions standards;
regulation of transportation, storage
and disposal of sludges from storage
tanks and spill clean-ups; Incorporation
of environmental (Including emissions)
considerations in specifications for
the product
Similar to those for gasoline
(continued)
-------
TABLE 49. (CONTINUED)
Major Anticipated
Uses
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Regulatory
Considerations
Coal Gases
~~
LPG
Feed-
itro-
chemlcals
(ethylene,
benzene,
toluene,
xylene, etc.)
Heating fuel for
Industrial,
commrclal and
residential use;
chemical feed-
stock
Fuel for Indus-
trial/domestic
heating and
appliances and
transportation
and Industrial
equipment;
chemical feed-
stock
Chemical feed-
stocks for
a range of
products In-
cluding
synthetic
fibers,
plastics,
solvents, etc.
Traces of metal carbonyls,
hydrogen sulflde and CO
Coal-derived Impurities
Coal-derived Impurities
Inhalation hazard
(asphyxiation can re-
sult upon exposure to
air containing high
levels of major
components of SNG);
occupational cancer
due to prolonged
exposure to certain
metal carbonyls
Inhalation hazards:
hazardous
emissions from
Incineration of
Impurities
Depending on the spec-
ific product type/Impur-
ities and uses can
present Inhalation, der-
mal and Injestlon
hazards to workers and
public and Industrial
users during handling,
transport and use of
products; potential
for air and water
pollution resulting
from spills and leaks
and evaporative emis-
sions from product
storage tanks; disposal
of sludges from spills
and storage tanks
In-plant process control and treatment
to minimize formation of trace contaminants
(e.g., proper operation of methanator
to reduce formation of nlckle carbonyl);
specification regulrements for SNG
Identical to those for natural gas
In-plant process control to minimize/
eliminate product Impurities; specification
for requirements Identical to those for
petroleum LPG
In-plant process control to minimize/eliminate
product Impurities; development of specifica-
tions similar to those for currently
available Identical products, or revised
specifications which take Into account
potential environmental hazards; strict
regulation of design and operation of
sources of evaporative emissions (transfer
linos, storage tanks, spills/leaks); devel-
opment of spill control contingency plans;
regulation of transportation, storage and
disposal of hazardous sludges from storage
tanks and spill clean-ups
(continued)
-------
TABLE 49. (CONTINUED)
Product
Major Anticipated
Uses
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Regulatory
Considerations
CO
en
Middle
distillates
(Jet fuel,
kerosene.
dleiel oil
and heating
oil)
Residuals
(heavy fuel
oil, lubri-
cants, wax
asphalts)
Fuel for jet air-
craft, gas tur-
bines, dlesel
engines and
residential/
commercial heat-
Ing
Industrial,
utility and
marine fuel;
preparation
of lubricants,
waxes, asphalt
and special
oils
High content of aroma tics
(1n lower cuts), volatile
compounds and toxic sub-
stances Including
potentially carcinogenic
substances 1n the higher
boiling fractions
Toxic substances Including
potentially carcinogenic
substances In the high
fractions; high nitrogen
content; volatile com-
pounds
Same as for naphtha
Exposure of workers to
product during handling
and transport; air, water
and soil contamination as
a result of spills; and
leaks. Disposal of
sludges from storage
tanks, spill clean-ups
and air/water pollution
associated with combus-
tion; disposal of
combustion ashes; emis-
sions of NOv, trace
elements and specific
PNA's during combus-
tion
Same as for Jet fuels; plus (for
heavier cuts) minimize worker
exposure via use of protective
clothing, and appropriate Industrial
hygiene and operating practices
Design, operation and maintenance of
storage tanks, pipelines, pumps and
other equipment to provide for
maximum containment and minimum
potential for spills and leaks.
Minimize worker exposure (skin) via use
of protective clothing, enforcement of
appropriate Industrial hygiene and
operating practices; development of spill
control contingency programs; employ-
ment of combustion modification to re-
duce air emissions; development and
enforcement of appropriate emissions
standards; regulation of transportation,
storage and disposal of sludges from
storage tanks and spill clean-ups and
combustion ashes and sludges
(continued)
-------
TABLE 49. (CONTINUED)
Product
Major Anticipated
Uses
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Regulatory
Considerations
By-product
chemicals
(aldehydes,
alcohols,
ketones, etc.)
Industrial
uses; chemi-
cal feed-
stocks
Coal-derived Impurities
Same as for petro-
chemicals
Same as for petrochemicals and
other hazardous cheilcal manufacturing
processes.
CO
a\
-------
TABLE 50. SOURCES AND NATURE OF ENVIRONMENTAL CONCERNS IN THE UTILIZATION OF
COAL GASES
Product
Major Anticipated
Uses
Expected Characteristics of
Potential Environmental
Consequence
Potential Environmental
Concern for Anticipated
Uses
Applicable Controls and Regulatory
Considerations
SNG
Low/medium-
Btu gas
CJ
Methanol
Heating fuel for
Industrial, com-
merlcal and
residential use;
chemical feed-
stock
Medium-Btu gas:
boiler fuel and
feedstocks for
chemical In-
dustry;
low Btu gas:
fuel for In-
dustrial
furnaces and
small boilers
Production of
gasoline;
blending with
motor gaso-
line; chemical
feedstock;
Industrial
applications
Traces of metal carbonyls,
hydrogen sulflde and CO
A range of toxic contam-
inants, Including hydrogen
sulflde, carbonyl sulflde,
hydrogen cyanide, metal
carbomyl, ammonia and
trace elements
Toxldty (Injeitlon/
Inhalation) and
evaporative emissions,
possible presence of
hazardous coal-derived
Impurities
Inhalation hazard
(asphyxiation can re-
sult upon exposure to
air containing high
levels of major
components of SNG);
occupational cancer
due to prolonged
exposure to certain
metal carbonyls
Worker exposure hazard
resulting from pro-
longed Inhalation of
contaminants; Inhala-
tion hazard due to
exposure to gas or air
having a high amount
of gas components (e.g.,
asphyxiation due to
CO Inhalation; emission
of hazardous combustion
products
Exposure of workers and
service station attend-
ants and motorists
(when added to gasoline)
to evaporative emissions
during handling, trans-
fer and transport; air,
water and soil contam-
ination resulting
from spills; disposal of
sludge from storage
tanks and spill clean-ups
In-plant process control and treatment
to minimize formation of trace contaminants
(e.g., proper operations of methanator
to reduce formation of nlckle carbonyl);
specification requirements for SNG
Identical to those for natural gas
Design, operation and maintenance of equip-
ment to provide for maximum containment
and minimum potential for leaks and
large-volume accidental discharges;
minimize worker exposure via use of
protective equipment and acceptable
operating practices; employment of com-
bustion modification to reduce air
emissions; development and enforcement
of appropriate emissions standards
Strict regulation of design and operation of
sources of evaporative emissions (transfer
lines/equipment, storage facilities and
spills/leaks); development of spill control
contingency programs; development and
enforcement of appropriate emissions
standards; regulation of transportation,
storage and disposal of sludges from storage
tanks and spill clean-ups, Incorporation.
of environmental considerations 1n
product specifications
(continued)
-------
TABLE 50. (CONTINUED)
Product
Petrochemicals
(tthylene,
propylene,benzene
toluene and
xylene)
Gailfler t«r»,
oil* and phenol*
Major Anticipated
Uses
Chemical feed-
stocks for the
production of a
rang* of product!
(synthetic
fibers, solvent*,
Industrial
commodities)
On-1 He combus-
tion; purifica-
tion and sale
for Industrial
utti and
chemical
feedstocks
Expected Characteristics of
Potential Environmental
Consequence
Coal-derived Impurities
Highly toxic aromatlcs,
Including benzene and
phenols; potentially
carcinogenic substances
In tars/oils
Potential Environmental
Concern for Anticipated
Uses
Depending on the spec-
ific product type/Impur-
ities and uses, can
present Inhalation, der-
mal and Injestlon
hazards to workers and
public and Industrial
users during handling,
transport and use of
products; potential
for air and water
pollution resulting
from spills and leaks
and evaporative emis-
sions from product
storage tanks; disposal
of sludges from spills
and storage tanks
Emission of hazardous
combustion products
(when burned on-slte);
exposure of workers
during handling and
transport; potential
air and water pol-
lution resulting
from spills and leaks
and evaporative emissions
from product storage
tanks; disposal of
sludges from product
storage tanks and spill
clean-ups
Applicable Controls and Regulatory
Considerations
In-plant process control to minimize/eliminate
product Impurities; development of specifica-
tions similar to those for currently
available Identical products, or revise
specifications to take Into account
potential environmental hazards; strict
regulation of design and operation of
sources of evaporative emissions (transfer
lines, storage tanks, spills/leaks); devel-
opment of spill control contingency plans.
regulation of transportation, storage and
disposal of hazardous sludges from storage
tanks and spill clean-ups
Development and enforcement of appro-
priate standards for combustion of
by-products; strict regulation of design
and operation of sources of evaporative
emissions (transfer lines, storage tanks,
spills/leaks); development of spill
control contlnengency plans; minimize
worker exposure via requirement for use
of protective clothing, enforcement of
appropriate Industrial hygiene and
operating practices; development of spill
control contingency programs; regulation
of transportation, storage and disposal
of sludges from storage tanks and spill
clean-ups and combustion ashes and
sludges
-------
relates to air pollution resulting from product uses such as gasoline in
automobiles (for example, motorists at service stations), and hazardous
fugitive emissions from storage tanks, product transfer points, leaks/
spills, and product uses (for example, products produced from
petrochemicals). Accidental spills and activities related to the
management of sludges from product storage tanks and spill clean-ups, and
solid, liquid and gaseous wastes associated with combustion and
combustion-related air pollution control would all contribute to general
environmental pollution.
5.3 APPLICABLE CONTROLS AND REGULATORY CONSIDERATIONS
5.3.1 Applicable Controls and Mitigation Measures
Tables 48, 49, and 50 summarize some of the control measures and
regulatory considerations for the mitigation of the major environmental
concerns identified for various anticipated uses of synfuel products. The
occupational exposure to synfuel products could be minimized through
development and enforcement of OSHA-type regulations that would lead to the
proper design, operation, and maintenance of product storage tanks,
pipelines, pumps, and other equipment to provide for maximum containment
and, hence reduced evaporative emissions and minimum potential for spills
and leaks. Workplace-related controls could also include requirements for
use of protective clothing, adherence to strict industrial hygiene and
operating practices, and development of spill control contingency plans.
The risk of public exposure can be reduced by developing and enforcing
(1) product specifications that take into account the potential direct or
indirect (for example, via emissions of hazardous combustion products)
health hazards to users; (2) emissions standards for stationary and mobile
combustion sources using synfuel products; and (3) requirements for
installing appropriate equipment or devices that would reduce emissions
during product transfer (for example, use of vapor recovery systems on
gasoline service station pumps/lines). The potential for contamination
stemu ing from waste disposal and spill control activities can be minimized
by developing and enforcing regulations for proper storage, transportation,
and disposal of synfuel product wastes that would significantly threaten
the environment and public if they were improperly managed.
Only some of these environmental concerns and regulatory considera-
tions are covered under existing or proposed environmental regulations.
For the remaining areas of concern, new legislations and regulations would
be required. A review of some of the provisions of the existing federal
regulations relevant to the environmental issues associated with synfuel
product utilization is presented in the following section. State
regulations and local ordinances are too numerous and are not covered here.
139
-------
5.3.2 Significant Relevant Statutes and Regulations
Six major federal environmental statues that would have bearings on
some of the environmental concerns discussed here are the Occupational
Safety and Health Act (OSHA); Toxic Substances Control Act (TSCA); Clean
Air Act (CAA); Resource Conservation and Recovery Act (RCRA); Clean Water
Act; and the Comprehensive Environmental Response, Compensation, and
Liability Act (Superfund legislation).
Toxic Substances Control Act (TSCA)
The Toxic Substances Control Act authorizes EPA to promulgate
regulations for the control of substances or mixtures of substances that,
in EPA's judgment, present an unreasonable risk to health and to the
environment through their manufacture, processing, and distribution in
commerce, use, or disposal. Such regulations may prohibit the manufacture,
processing, etc., of certain substances and impose restrictions on others.
The Act also directs EPA to issue regulations for testing, premarket
notification, and reporting and retention of information. Under Section 4
of TSCA, EPA is empowered to require developers to develop adequate data
with respect to the effects of their products on health or the environment.
Where an industry such as the synfuel industry has not developed sufficient
data and where EPA finds that unreasonable risks may occur, TSCA grants the
authority to require that testing be-performed.
Under TSCA, premanufacture notices (PMN's) must be submitted on
chemicals not listed in a Chemical Substance Inventory. Many synfuel
substances are not included in the Inventory and therefore require a PMN.
Other synfuel products (for example, methanol) are present in the TSCA
Inventory, but unless EPA operates on the premise that synfuel products are
inherently different from their existing commercial counterparts and
represent new products/uses, a PMN may be required. A PMN, which must be
submitted to EPA at least 90 days before beginning commencement of
manufacture for commercial purposes, requires the following data:
1) Chemical composition of the products
2) Details on mode of use
3) The projected production volume
4) A characterization of the by-products and emissions resulting
from the manufacturing process and characterization of the
product of combustion during its intended use
5) Characterization of human exposure during the manufacturing
process and use of the products
6) Method by which manufacturing and processing wastes are disposed
of.
140
-------
If EPA determines that sufficient data have not been submitted to make
a reasonable assessment of the risks posed by a synfuel product
and believes that the product may present an unreasonable risk to man or to
the environment, it could restrict the manufacture or use of the product.
The authority of TSCA extends to products/by-products of the synfuel
industry that are on the Inventory or that have already passed through a
PMN process if EPA determines, on the basis of new data, that additional
data reporting and testing are required. At the present time, synfuel
producers are being requested to contact the Office of Toxic Substances
within EPA to determine whether their products are on the TSCA Inventory or
will require a PMN. EPA's approach to the regulation of synfuel products
under TSCA is still being formulated.
Clean Air Act (CAA)
The Clean Air Act provides the EPA the authority to regulate new and
existing sources of air pollution in order to attain and maintain levels of
air quality that will protect public health and welfare. To date, most
existing and planned air quality regulations developed under the CAA focus
on criteria pollutants (that is, SO , NOX, CO, particulate matter) in
ambient air. Criteria pollutants associated with synfuel utilization are
expected to be emitted from fuel transportation, storage, and combustion in
utility and industrial boilers, residential/commercial furnaces, gas
turbines and various mobile sources. Current New Source Performance
Standards (NSPS) for fossil-fuel-fired power plants contain special
standards for facilities using certain synfuels.
At the present time, regulations are planned that will set standards
for industrial boilers and stationary internal combustion engines;
currently no emissions standards for commercial and residential boilers and
heaters exist. There are also no emissions standards for the
transportation and handling of either petroleum or synfuel products from
production and refining sites to end-use locations. However, New Source
Performance Standards (NSPS) were recently promulgated on petroleun
storage, and they include storage requirements for synfuels. NSPS's are
also planned for volatile organic carbon (VOC) emissions from aasoline bulk
terminal loading facilities, including tank trucks.
Resource Conservation and Recovery Act (RCRA)
Under RCRA, EPA has broad authority for the identification and
regulation of the handling, transportation, and disposal of hazardous
wastes. Wastes currently listed as hazardous under RCRA from both specific
and non-specific sources do not include synfuel products/by-products per
se. However, certain chemical products and manufacturing chemical
intermediates listed as toxic materials in RCRA paragraph 261.33f (May 19,
1980 Federal Register) may be present in certain synfuel products (for
example, benzo(a)anthracene). Disposal of spills of these products would
be subject to RCRA jurisdiction if quantities exceeded 1,000 kg. Certain
additional commercial products and manufacturing chemical intermediates
141
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listed as toxic materials in RCRA paragraph 261.33e (for example, nickel
carbonyl) may also be present in synfuel products (for example, SNG).
Disposal of spills of these products would come under RCRA regulation if
quantities exceeded 50 kg.
Wastes from the combustion of synfuels have not been regulated. RCRA
currently exempts as "special wastes" fly ash and other products generated
primarily from the combustion of coal or other fossil fuels. Synfuel
sludges (for example, those resulting from product storage) are not listed
as hazardous wastes under RCRA but must be evaluated for possible listing.
Waste packing, seal ings, oil, and various residues that may be generated
during synfuel utilization may become identified as hazardous wastes under
RCRA and come under subsequent regulation as further information is
obtained on the characteristics of these wastes. Management of specific
wastes under RCRA is an evolving process, and it would be very timely to
bring to the attention of EPA's Office of Solid Waste some of the
environmental concern associated with synfuel wastes.
Clean Water Act (CWA)
The Clean Water Act provides EPA with authority to regulate point
source discharges of pollutants and spills of oil and hazardous materials
in order to protect the quality of navigable waters. The Act directs the
EPA to promulgate and enforce national standards of performance for all new
sources and pretreatment standards for industrial discharges into publicly
owned treatment plants and to control discharges of toxic substances. To
date, no NSPS standards have been promulgated for the synfuel industry,
although the Effluent Guidelines Division of EPA is currently involved in
major studies to develop background data for regulation of the energy
industry. Section 402 of the FWPCA, National Pollutant Discharge
Elimination System (NPDES), authorizes an EPA- or state-administered permit
system for discharges into navigable waters. The permit for a point source
discharge specifies the materials and quantities to be discharged,
discharge conditions, and the monitoring and reporting systems to be used.
Many pollutants (for example, phenolic compounds) currently regulated under
effluent guidelines for other industries are present in synfuel products/
by-products and wastes. It is anticipated that these will be regulated via
NPDES permits for individual facilities producing and using synfuel
products.
Under the CWA, several spill control regulations apply to the storage
of certain synfuel materials. However, these regulations are not complete
and there are still several regulatory unknowns concerning the transport of
synfuel products over or near waterways.
Occupational Safety and Health Act (OSHA)
This act authorizes the U.S. Department of Labor (DOL) to set
mandatory standards to safeguard the occupational safety and health of all
employers and employees of businesses engaged in interstate commerce.
Among the standards promulgated to date under OSHA are those oertaining to
142
-------
worker exposure to toxic and hazardous air contaminants, many of which are
identified as potential constituents of SNG and by-products. Table 51
lists OSHA standards for some of the materials that are known or expected
to be present in SNG and coal gasification by-products. Such products and
by-products may subject plants providing and using coal-derived SNG and
by-products to OSHA regulations. The presence of the substances shown in
Table 51 in the ambient environment in such facilities may result from
fugitive or evaporative emissions from various production, transportation,
and storage units; from accidental spills; or from equipment or system
failure. For many of these substances, OSHA standards are not expected to
be exceeded under normal operating conditions primarily because of the
closed nature of many of the facilities producing and using SNG and coal
gasification by-products. For some highly volatile substances such as
benzene, evaporative emissions must be controlled in order to comply with
the ambient standards.
Under the authority of OSHA, regulations have been promulgated
relating to exposure to some 17 occupational carcinogens. Although some of
the regulated carcinogens (for example, benzidine and naphthylamines) are
expected to be present in SNG tars and oils, it is not envisioned that
their concentrations would exceed those levels that would make the by-
products subject to OSHA regulations. The National Institute of
Occupational Safety and Health (NIOSH) has published a list of suspected
carcinogens covering some 1500 chemical substances. Some of these
substances would be present in SNG product/by-products and are subject to
future regulations by OSHA.
The existing OSHA ambient regulations cover the majority of substances
that are known to be present in SNG products and by-products. As better
and more detailed composition data become available for such materials and
for materials from other synfuels processes, it is possible that additional
OSHA regulations may be developed covering toxic substances not yet
identified in SNG and other synfuel products and by-products.
To date, OSHA regulations affecting synfuels have been directed at
specific compounds. Safety regulations based on OSHA can also be aimed at
an entire industry, but such regulation is not anticipated for synfuels.
At the present time, OSHA does not have any on-going work dealing with
synfuels (Reference 44). However, NIOSH is interested in synfuels.
Concern over possible hazards caused by synfuel production (Reference 45)
and use was indicated in a recent journal article by several OSHA
personnel. Comparison with analogous fuels was the basis for speculation
on the hazards of synfuels. Regulation and control of identified hazardous
chemicals was advocated.
Comprehensive Environmental Response, Compensation, and Liability Act
(Superfund Legislation)
The superfund legislation, recently signed into law, authorizes
federal action to contain and clean up spills and other releases of
hazardous substances, as well as abandoned disposal sites. Under the
143
-------
TABLE 51. OSHA STANDARDS FOR MATERIALS KNOWN OR SUSPECTED TO BE
PRESENT IN LURGI SNG PLANTS (37)
Q* "iHMjnd
Acetic acid
Arnonu
Aniline (siin)
Antincny
Arsenic
Benzene
Beryl liura
Butyl nercaptan
Cadmium (iust)
Carbon dioxide
Carbon disulfide
Carbon monoxide
Carbon tetrachloride
Chromium, soluble salts
Chromium, Insoluble salts
Coal dust (<5: Si02)
(>:-. Sio2)
Coal tar pitch volatile* *
Cresol (skin)
Ethyl benzene
Ethyl nercaptan
Hydrogen chloride
Hydrogen sulflde
Hydrogen cyanide
Lead and Inorganic lead
compounds
Manganese
Mercury
Hethanol
Methyl mercaptan
Naphtha (coal tar)
Naphthalene
Nickel carbonyl
Nickel metal and soluble
compounds (as Hi)
Nitrogen dioxide
Phenol (skin)
Propane
PyHdlne
Selenium compounds
Silica (respirable)
(total dust)
Styrene
Sulfur dioxide
Toluene
Vanadium
Xylene
T'.JA , • I'pn
10
50
5
--
--
10(1)
--
10
--
5000 (10.000)
20(1)
50(35)
10
--
--
--
--
--
5
100
--
--
--
in
—
--
--
200 (200)
--
100
10
0.001
—
5(1)
5
1000
s
"
—
"
100
5(2)
200 (100)
—
100 (100)
Ti.\; „„,•„•>
r*j
35
•o
0.5
0.5
o.oj> (o.oo:)
35
0.2 ( 04)
9000 (13,000)
--
55
1
0 5 (0 025)
1
2.4
0.10
0.2
22
35
435
--
--
--
0.2 (0.10)
--
0.1 (0.05)
260
--
400
50
0.07
1
9
19 (20)
1800
15
0.2
0.10 (0.05)
0.30
--
13
--
(1)
435
''i 1 i'i l.l'.'ii1 1. 01 1 Ill'l
LiMiivnri .it um
-.
M)
--
--
(.00? mg/ro3)
?5 ppn
005 r)/n3
--
0.6 mg/m3 (0,2 n.g/m3)
(30, COO ctn)
30 ppm ( 1 0 ppm)
(200 ppm)
25 ppn
(0.05 mg/n3)
--
--
--
--
--
--
10 ppm
5 ppm
20 ppm (10 ppm)
25 ppn
—
5 mg/m-'
--
10 ppm
--
--
(60 mg/m3)
--
--
--
--
--
--
—
(0.05 mg/m3)
--
I/ho o Found
GJ^ sliiMi'1, mi liquor
Gas stream, gjs lii|nor
Trace element in coal
Trace elenent in coal
Gas strejn, njrhtha
Trace clement in coal
Gas stream, naphtha
Trace elercnt 'n real
Gas stream
Gas stream
Gas stream, product SNG
Laboratory
Trace element in coal
Coal preparation areas
Gas stream, tars, oils
Gas stream, naphtha
Gas strcan, napth;<
Gas stream, naphtha
Stream
Gas stream
Gas strcan
Trace elenent in coal
Trace element in coal
Trace elenent in coal
Rectlsol solvent
Gas stream
Gas stream, tars, oils
Gas stream, tars, oils
Hethanation areas, product SNG
Trace element in coal
Incinerated wastes, boiler flue gases
Gas and gas liquor
Gas stream
Gas stream, tars, oils
Trace element in coal
Incinerated wastes, boiler flue gases
Gas stream tars, oils
Trace clement in coal
Gas stream, tars, oi Is
Time-weighted average. Numbers in parentheses indicatP HIOSH recomwnded standards
fCoal tar pitch volatile;, as ixasurcd by the benzene-soluble fraction of particulate matter, includes such polycyclic
aromatic hydrocarbons as anthracene, b^nzotajpyrenr, phenjnthrene, acrldine, chrysen^, and p/rcnc.
144
-------
mandate of the superfund legislation, liability can be imposed on the
generators of the hazardous substances to compensate for cleanup expenses
and damage to persons or property. Additional interpretations and
ramifications of the superfund legislation are expected as the Act is
implemented. Spills of synfuel products/by-products that are considered
hazardous would be subject to superfund mandates.
5.4 ENVIRONMENTAL IMPACTS ASSOCIATED WITH VARIOUS PRODUCTION AND USE
SCENARIOS AND REGIONAL CONSIDERATIONS
As will be discussed in Section 6, for near-term regulatory planning
purposes certain shale oil products, medium-Btu gas, and coal liquids have
been identified as presenting greater environmental concern. Figures 17
through 23 present the quantities and utilization patterns for shale oil,
low-/medium-Btu gas, and direct and indirect liquefaction products, based
on the data summarized in Section 3.3.5. Similar diagrams can be developed
for other scenarios. As noted in these figures, except for oil shale in
the 1988-1992 and 1993-2000 time frames (Figure 18) and direct coal
liquefaction in the 1993-2000 time period (Figure 23), the transportation,
distribution, and use of products are expected to be confined to the
region(s) where each synfuel is produced. This implies that the
environmental impacts associated with product utilization are expected to
be confined primarily to the production regions, except for impacts
associated with the natural transport of pollutants across regional
boundaries (for example, transport of air pollutants emitted from
combustion sources). The projections shown in Figures 17 through 23
indicate that up to the year 2000 under Scenario II the environmental
impacts of synfuel product utilization would be expected to be largely
limited to EPA Regions V and VIII for oil shale (Figures 17 and 18), to EPA
Regions IV, VI, and VIII for medium-Btu gas (Figure 19), to EPA Regions
III, IV, and VIII for indirect coal liquefaction products (Figures 20 and
21) and to EPA Regions III, IV, and V, for direct liquefaction products
(Figures 22 and 23).
A detailed discussion of the projected synfuel production,
distribution, and utilization patterns and their regional environmental
impacts are presented in the following paragraphs, using shale oil and
low-/medium-Btu gas (Figures 17 through 19) as examples.
5.4.1 Shale Oil Products
Figure 17 presents the estimated quantities and utilization pattern
for the shale oil products under Scenario II and the 1980-1987 time frame.
As noted in the figure, an estimated 77,000 BPD of shale oil will be
produced (in EPA Region VIII); the shale oil will be hydrotreated and
refined into middle distillates (57,000 BPD), gasoline (13,000 BPD), and
residuals (7,000 BPD) which will be used by various commercial,
residential, and industrial establishments for heating and transportation
145
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PRODUCTION
REGION VIII
en
HYDRO-
TREATING
REFINERY
REGION VIII
o
3D
o
m
o
o
3)
C
O
MID DISTILLATES
JiT
REGION VIII
GASOLINE
13
REGION VIII
RESIDUALS
7
REGION VIII
12.3
2.3
3.7
0.7
0.2
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
ELECTRIC UTILITIES
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
UTILITIES
-I BOILER FUEL
FIGURE 17.
Estimated Utilization Pattern For Shale Oil Products;
Scenario II, 1980-1987 Time Period (Amounts Shown Are
lO^ BPD Oil Equivalent; S Designates Storage)
-------
PRODUCTION
REGION VIII
REFINERY
REGION VIII
REFINERY
REGION V
MID DISTILLATES
155
REGION VIII
GASOLINE
36
REGION VIII
RESIDUALS
19
REGION VIM
MID DISTILLATES
148
REGION V AND VII
GASOLINE
34
REGION V AND VII
RESIDUALS
18
REGION V
FIGURE 18.
Estimated Utilization Pattern For Shale Oil Products;
Scenario II, 1988-1992 and 1993-2000 Time Periods
(Amounts Shown Are 103 BPD Oil Equivalent; S Designates
Storage)
TRANSPORTATION
TRANSPORTATION
UTILITY
INDUSTRY
TRANSPORTATION
UTILITY
INDUSTRY
TRANSPORTATION
TRANSPORTATION
TRANSPORTATION
-------
PRODUCTION
(REGION IV)
MEDIUM
BTU GAS
30
REGION IV
BOILER FUEL
CHEMICAL FEEDSTOCK
PRODUCTION
(REGION VI)
MEDIUM
BTU GAS
30
REGION VI
TARS, OILS
0.98 - 1.9
REGION VI
PHENOLS
0.15-0.30
REGION VI
NAPHTHA
0.25 0.72
REGION VI
BOILER FUEL
CHEMICAL FEEDSTOCK
S H CHEMICAL FEEDSTOCKS
SH CHEMICAL FEEDSTOCKS
SH CHEMICAL FEEDSTOCKS
PRODUCTION
(REGION VIII)
MEDIUM
BTU GAS
30
REGION
VIII
TARS, OILS
0.98 1.9
REGION VIII
PHENOLS
0.15-0.30
REGION VIII
NAPHTHA
0.25 0.72
REGION VIII
BOILER FUEL
CHEMICAL FEEDSTOCK
S H CHEMICAL FEEDSTOCKS
SH CHEMICAL FEEDSTOCKS
S H CHEMICAL FEEDSTOCKS
Figure 19.
Estimated Utilization Pattern for Low-/f1edium-Btu Coal Gas:
Senario II, Period 1980-1987; Production and Utilization
Patterns for the 1988-1992 and 1993-2000 Are the Same As
Shown Here But Production Quantities Differ (Amounts Shown
Are 10 BPD Oil Equivalent; S Designates Storage)
148
-------
COMMERCIAL
PRODUCTION
REGION VIII
100
GASOLINE
.64.5 i
REGION VIII '
' 3-5 (^)
\ 60-5 /7N
xiy
INDUSTRIAL I
TRANSPORTATION I
MID DISTILLATES
2.5
REGION VIII
RESIDUALS
0.7
REGION VIII \
SNG
32.6
REGION VIII
LPG
0.1 |
' REGION VIII ^
0-2 /T\
/ W
°'4 (^)
o.oe /^TN
\ °-02 r^
0.07 ^
I (!L)
' 0.01 s~\
\ 0.02 /TN
COMMERCIAL
INDUSTRIAL
TRANSPORTATION I
ELECTRIC UTILITIES 1
RESIDENTIAL I
COMMERCIAL
INDUSTRIAL
0.3 ,
(— ~ (
0.27 ,
I (
0.4 (
1.5 /
\
0.03 t
\
10.7
~ — (
6.9
I (
12.2 .
0.8 ,
\
2.0 ,
\
TARS, OILS, PHENOLS
REGION VIII
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
ELECTRIC UTILITIES
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
ELECTRIC UTILITIES
CHEMICAL FEEDSTOCKS
BOILER FUEL
FIGURE 20.
Estimated Utilization Pattern For Indirect Coal Liquefaction
Products; Scenario II, 1988-1993 (Amounts Shown Are 10 BPD
Oil Equivalent; S Designates Storage)
-------
PRODUCTION
REGION VIII
PRODUCTION
REGION IV
PRODUCTION
REGION III
s — ^ ?nn
/ r )
\^J RFC; ION
VIII
GASOLINE
/7\ 15° /
^D REGION IV \
GASOLINE ,
,0x300 1
W REGION III \
0.9
I^AQPil IMP /
Q 129 / 7.Q
\
\ 121.1
21.4
13.8
CM/"*
OPiU
/O\ ^^ 24-4
1.6
4.0
UlLoLL 1 Ut L
©c n
o.u
0.4
/
/
RESIDUE / °-8
/Oj 1'4 /
W \ 0.15
\
\
\ 0.05
0.14
LPG /
Lru /
/T\ °-2 / °-02
vL/ \
\ ««>,
\ 0.04
/T\ 1-0
®0.5
\ 0, 14«-5
\ J
/T\ 2-4
f
©1.2
\ (0, 296.4
PHMMPRPI Al
IKini ICTDI Al
TQ AMCPADTATIHM
RPQIHPMTI Al
POMMFRTIAI
IKIDI IQTRI Al
TR AMCOODT ATirMM
Fl PPTHIP NTH ITIPQ
PHMMPRPI Al
IKini IQTRI Al
TRANSPORTATION
PI PPTPIP IITM ITIPQ
DPQinPMTlAI
ntOlUtiN 1 IML
P/^MMP RPI A 1
IfUfM ICTD 1 A 1
IrJUUo 1 nIAL
POH4IUIP DPI A I
UUMMt n^lAL
IMHI IQTRI Al
TR AKjcpPiRTATlON
rOMMFRriAl
IKIHI IQTRI Al
TRANSPORTATION
Figure 21. Estimated Utilization Pattern for Indirect coal Liquefaction
Products; Scenario II, 1993-2000 (Amounts Shown Are 20 BPD
Oil Equivalent; S Designates Storage)
150
-------
PRODUCTION
REGION V
50
REFINERIES
REGION V
NAPHTHA
15.4
REGION V
MIDDLE
DISTILLATES
18.7
REGION V
RESIDUALS
10.0
REGION V
LPG
5.9
REGION V
S ) 15'4? | CHEMICAL FEEDSTOCKS
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
INDUSTRIAL
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
FIGURE 22 Estimated Utilization Pattern For Direct Coal Liquefaction
Products; Scenario II, 1988-1992 Time Period (Amounts Shown
Are 10 BPD Oil Equivalents; S Designates Storage)
TRANSPORTATION
ELECTRIC UTILITIES I
j
TRANSPORTATION
ELECTRIC UTILITIES
TRANSPORTATION
-------
KD
NAPHTHA
154
MIO DISTILLATES
187
x—\ 154? I i
-(S) 1 CHEMICAL FEEDSTOCK |
RESIDUES
100
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
TRANSPORTATION
ELECTRIC UTILITIES
COMMERCIAL
TRANSPORTATION
ELECTRIC UTILITIES
Tvli.
308 >
44
{T) '—\ CHEMICAL f EEOSTOCK J
{ RESIDENTIAL
{ COMMERCIAL
{ INDUSTRIAL
1
1
1
\ TRANSPORTATION J
{ RESIDENTIAL
| COMMERCIAL
1
1
{ INDUSTRIAL |
| TRANSPORTATION ]
-| TRANSPORTATION J
FIGURE 23.
Estimated Utilization Pattern For Direct Coal Liquefaction
Products; Scenario II, 1993-2000 Time Period (Amounts Shown
Are 10^ BPD Oil Equivalent; S Designates Storage)
152
-------
purposes.* The estimated crude shale oil production rates under Scenarios
I and III for the 1980-1987 time frame will be 219,000 BPD and 340,000 BPD,
respectively. Except for higher quantities of the products, the relative
amounts of the products for Scenarios I and III are expected to remain the
same as those shown in Figure 17 for Scenario II. In the 1980-1987 time
frame for all three scenarios, the production, transportation, refining,
distribution, and uses of shale oil products, and hence the associated
environmental impacts, are expected to be almost totally confined to EPA
Region VIII.
Information similar to that shown in Figure 17 for the 1980-1987 time
period is presented in Figure 18 for the 1988-2000 time frame. For
Scenario II during this time frame, an estimated 410,000 BPD of shale oil
will be produced and hydrotreated in EPA Region VIII; the hydrotreated
product will be transported by pipelines to refineries in Regions VIII and
V and refined into gasoline, middle distillate, and residuals. It is
anticipated that direct use of hydrotreated shale oil as boiler fuel would
be insignificant during this time frame.
Except for some of the products refined in Region V that would be
shipped to users in Regions VII (for example, gasoline and middle
distillates), for all practical purposes the distribution and use of
refined shale oil products, and hence the environmental impacts associated
with such refining, distribution, and use, are expected to be largely
confined to Regions VIII and V. Except for higher production levels and
product quantities for Scenarios I and III (437,000 BPD and 750,000 BPD of
crude, respectively), the refining and use patterns shown in Figure 18 are
also applicable to production Scenarios I and III.
The hydrotreated shale oil would be transported from production sites
to refineries through pipelines. Depending on the relative location and
capacity of the existing pipelines feeding refineries, these same pipelines
or new, dedicated pipelines will be used to transport hydrotreated shale
oils. The use of existing pipelines would most likely involve some degree
of blending of shale oil and petroleum crude. At present, it is very
difficult to forecast which specific refineries will receive the
hydrotreated shale oil and what fraction of each refinery's total feedstock
will be comprised of hydrotreated shale oil. Within a refinery,
considerable blending of various shale oil and petroleum intermediate and
process streams would be expected to take place and the final products
which will be produced to specifications (aromaticity, viscosity,
volatility, etc.) are expected to be composites of shale oil and petroleum
products and to contain varying fractions of shale oil-derived material.
*Some shale oil developers have indicated that at least some hydrotreated
shale oil may be initially used directly as boiler fuel if the
transportation links are not in place to carry the hydrotreated shale oil
to refineries.
153
-------
The total, overall contributions of shale oil to various products used
in EPA Region VIII (the region of maximum use under Scenario II) are
presented in Table 52 for 1980-1987 and 1988-2000 time periods. As noted
in the table, the shale oil would account for a substantial percentage of
the total feed to refineries in Region VIII (13.3 and 35.6 for the
1980-1987 and 1988-2000 time frames, respectively) and hence would be
expected to have significant impacts on the refinery operations and product
characteristics. Most of the shale oil is expected to be refined into
middle distillates (jet and diesel fuel) and gasoline with associated
production of some residuals. The middle distillate from shale oil would
account for a significant fraction of such distillates used in EPA Region
VIII. Based on the data presented previously on the environmentally
significant characteristics of shale oil products and the anticipated
refining and use pattern depicted in Figure 17 and Table 52, major areas of
environmental concern in Region VIII would relate to: (a) occupational
hazards in processing, transporting, and sale of shale oil middle
distillate, gasoline, and residuals derived from shale oil; (b) public
exposure caused by air pollution generated from the combustion of middle
distillates, gasoline, and residuals; evaporative emissions from product
storage tanks; and inhalation hazard to motorists at gasoline service
stations; and (c) environmental hazards associated with accidental spills
(for example, rupture of pipelines carrying products) and disposal of waste
from refineries, product storage tanks, spill clean-ups, and pollution
control systems used in conjunction with steam and power generation plants.
The mitigation measures applicable to the control of these anticipated
hazards were reviewed in Section 5.3.
5.4.2 Low-/Medium-Btu Coal Gas Products
The estimated quantities and utilization pattern for the
low-/medium-Btu gas products are presented in Figure 19 for Scenario II and
the 1980-1987 time period. Except for different levels of production, the
products and the utilization pattern shown in Figure 19 also apply to the
other scenarios and time frames.
Low-/medium-Btu coal gas is expected to be produced in EPA Regions IV,
VI, and VIII. Because it is not economical to transport medium-Btu gas
over distances greater than 200 miles (see Section 3.2.1), it is
anticipated that the products will be used in these same regions. Because
of its lower Btu content, the economics of transporting low-Btu gas are
even more unfavorable. Thus, it is expected that low-Btu gas will also be
used in the region where it is produced. Some low-Btu plants will probably
be located at the same site as the product user.
The gasifiers built in Regions VI and VIII are expected to use the
commercially available Lurgi technology, which generates relatively small
quantities of by-product tars, oils, phenols, and naphtha. The gasifiers
built in Region IV are expected to use the Texaco partial oxidation
technology, which is compatible with Eastern caking coals and does not
generate the by-product tars, oils, and phenols.
154
-------
TABLE 52. QUANTITY OF VARIOUS SHALE OIL PRODUCTS IN RELATION TO
PETROLEUM ANALOGS IN THE EPA REGION OF MAXIMUM SHALE
OIL PRODUCT USE AND ON A NATIONAL BASIS FOR SCENARIO II
1980 - 1987 1988 - 1992 and 1993 - 2000
% of total % of total
Total amount product in % of total Total amount product in % of total
of product region of product in of product region of product in
Product MM B/D max use U.S. used max use U.S.
Crude shale oil (fuel) 0.0008 1.3 0.45
01 Shale oil refinery feed 0.07 13.3 0.45 0.41 35.6 2.4
en
Middle distillate 0.057 37.6 0.75 0.32 48.3 7.0
Gasoline 0.013 4.8 0.2 0.07 2.3 0.9
Residuals 0.007 15.6 0.2 0.04 6.6 1.3
-------
As discussed in Section 3.2.1, transportation of low-/medium-Btu gas
would require a dedicated pipeline. Once delivered, it is suitable for use
as either boiler fuel or as a chemical feedstock, for example, in the
production of ammonia or methanol. Large chemical, petroleum, or steel
plants may require enough fuel at a single plant to economically justify
the dedication of an entire gasification plant. Another possibility is the
development of industrial parks centered around a gasification facility.
The extent to which medium-Btu gas will be used as chemical feedstock
rather than boiler fuel will be determined largely by economic
considerations, and one factor could be the extent to which additional
emissions control equipment will be required for boilers using
low-/medium-Btu gas.
The use of the Lurgi gasifier by-products is also uncertain. Because
of their high heating value and because the toxic hazards posed by their
distribution in commerce are not known, it is anticipated that these
products will initially be used at the production site as boiler fuel.
Eventually, markets for these substances may be developed, most probably as
chemical feedstocks. The quantities of Lurgi by-products generated are
highly coal-specific and thus are shown as a range in the diagram.
Based on the data presented previously on the environmentally
significant characteristics of low-medium-Btu gas products, the areas of
concern in EPA Regions VIII, VI, and IV would primarily relate to: (a)
occupational health and safety hazards in processing, transporting, and use
of products; (b) public exposure to air pollutants generated during
combustion of gas and by-products; and (c) environmental hazards resulting
from accidental spills (for example, rupture of pipelines), and disposal of
waste from production facilities, product storage tanks, spill clean-ups,
and systems used for pollution control.
156
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SECTION 6
PRIORITY RANKING OF SYNFUEL PRODUCTS FROM THE STANDPOINT OF
ENVIRONMENTAL CONCERNS
As was noted in Section 1, the primary objective of the synfuel
utilization study was to identify and examine the major environmental
concerns relating to synfuels utilization and to rank the synfuel products
(or groups of such products) from the standpoint of environmental concerns
and mitigation requirements. The study is to provide input to the EPA
effort for: (a) assessing the environmental implications of a mature
synfuel s industry and of large-scale utilization of synfuels products, and
(b) planning and prioritizing regulatory and research and development
programs. The anticipated industry development, product utilization
patterns, and environmental concerns associated with synfuel products were
presented in previous sections. The objective of this section is to rank
the synfuel products from the standpoint of environmental concerns and to
identify those products and areas of concern that should receive more
immediate and greater regulatory and R&D attention. The ranking is based
on the data presented previously and therefore is subject to the
limitations of the existing data and the assumptions used in developing
products and use scenarios and in estimating product characteristics (see
Section 7 for major limitations of the data base); the product rankings
will most likely change as more data become available, especially for those
products for which little or no characterization data are available at this
time. It should also be noted that the specific approach used here for
product ranking represents only one of the many approaches that could be
used to rank synfuel products from the standpoint of environmental
concerns.
Section 6.1 presents the general basis used for product rankings. The
product ranking is in part based upon an assessment of the environmentally
significant characteristics of synfuel products relative to petroleum
analogs; the basis for this assessment is explained in Section 6.2. The
rankings of the synfuel products are presented in Section 6.3.
6.1 BASIS FOR PRODUCT RANKING
The ranking of synfuel products, which is presented in Section 6.3,
was based on the following factors and considerations:
157
-------
• Reported or estimated environmentally significant characteristics
of synfuel products relative to those of petroleum analogs, based
on considerations of exposure potential, combustive and
evaporative emissions, toxic hazards, cost of control, and the
extent of regulatory protections under key existing environmental
legislations; products for which the environmental risks and
control needs are greater and for which less protections can be
anticipated under existing regulations have been given a higher
ranking (see Section 6.2 for an illustration of the environmental
attribute rating procedure)
• The estimated quantity of products used, both in absolute terms
and as percentages of the total (synfuel and petroleum) used
nationwide (Tables 53 through 55) and on a regional basis; the
greater the amount of the product used and the percentage of
usage, the greater the potential for presenting environmental
hazards, and hence a higher positive ranking.
t Considerable scientific and engineering judgement; because of the
lack of a solid data base, heavy reliance had to be placed on the
professional judgement of experts most familiar with the domestic
energy supply and demand picture, synfuel production/refining
technologies, expected environmental characteristics of synfuel
products, applicable controls, and regulatory needs.
Two approaches were examined for ranking synfuel products: (1)
ranking based on strict adherence to the limited product characterization
data currently available (Table 47); and (2) ranking based on the premise
that in the absence of detailed characterization data, and unless the
available data indicate otherwise, it would be reasonable to assume that a
synfuel product would be more hazardous. For the following reasons, the
first approach was selected and used to develop product rankings.
The second approach operates on the premise that if there is any room
for error in ranking synfuel products, it would be more advisable to err on
the safe side. This scenario asserts that, in the absence of detailed
characterization data and strong evidence to the contrary, synfuel products
by their very nature (new chemicals from a more "exotic" source)
should be considered more hazardous. Under this scenario nearly all
synfuel products would be given a positive ranking and the ranking system
would lose its usefulness as a guide in prioritizing regulatory and R&D
activities. Acquiring detailed characterization data and not necessarily
concentrating on products that have been established to present greater
environmental concern would be emphasized under the second scenario.
Under the first approach, a synfuel product would not necessarily be
considered more hazardous because of the mere lack of detailed
characterization data. Instead, assigning a more positive ranking to a
product is supported by actual data or based on strong indications of
greater potential hazards. Under the first scenario, prioritization of
X 3O
-------
TABLE 53, ESTIMATED QUANTITIES OF SYNFUEL PRODUCTS USED IN THE U.S.: 1980-87
Product
Crude sh,ile oil (fuel )
Sn-ile 01 1 refinery feed
Shale jet fuel
S.rI LrG
EDS fuel oil
EOS ryohtha
EDS LPG
H-coal fuel oil
M-coal naphtha
H-coal LPG
National tioa i
(medium)
Tutd 1 Amount
uf Synthetic
Product
MMSPD
0.02
0.20
0.04
0. 12
0.02
0.036
0.15
0.24
r, of total
Product in
U.S.
0.13
1.2
3.4
3.4
0.6
0.57
1.5
2.3
(;.0! 6.13
0.02
0.003
0.012
0.12
0.002
0.03
0
0.005
0.08
0
0
0
0
n
n
0
0
0
0.2
0.03
0.12
0.12
0.06
0.4
0
0.10
0.7
0
0
0
0
n
n
0
0
0
Nominal
(Low)
Totaf Amount '/. of total
of Synthetic Product in
Product U.S.
0 . 0008
0.07
0.015
0.042
O.OO/
0.13
0.09
0.04?
0
0.05
0.45
1.2
1 .2
0.2
0.2
0.9
0.4
0
0
0
0
0
0
0
0
0
0
0
0
0
0
n
n
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
n
n
0
0
0
Accelerated
(High)
Amount 'K iTFTT. §".
MMBPD
0.03
0.34
0.06
0. 18
O.OJ
O.Ob
0.15
0.2
2.0
5.4
5.4
o.y
0.8
1.5
0.24 Z.J
0.001
0.2
0.02
0.3
0.004
0.1
0.002
0.04
0
0.007
o.oa
0
0
0
0
1.0
0.06
0.6
0
0.15
0.7
0
0
0
0
n n
n
0
0
0
n
n
n
0
en
-------
TABLE 54. ESTIMATED QUANTITY OF SYNFUEL PRODUCTS USED IN THE U.S.: 1988-1992
Product
Crude shale oil (fuel )
Shale oil refinery feed
Shale jet fuel
Sndle diesel fuel
Shale residuals
Shale gasoline
"odium Btu gas (coal )
S'.G (coal)
Gas if ier tar;, c'.li
Gasi i ier ;)iienol
F-T LPG
F-T medium Btu gas
F-I s:;c
F-T heavy fuel oil
F-l c-Tsoline
!1-aasoline
F-f diesel fuel
Fuel n:ethanol
SRC II fuel oil
SRC II naphtha
SRC 11 LI'G
EDS fuel oil
EDS r.aphtha
EDS LPG
H-coal fuel oil
r.-coal naphtha
H-coal LPG
National Goal
(Medium)
'•/
/.:
Amount
0
0.11
n.oK
0.22
0.0/1
0.07
0.48
0.74
0.01
of total
in U.S.
0
2.4
6.5
6.5
1.3
0.9
5.0
7.7
0.1
0.02
0
0.012
0.07
0.001
0.03
0.1
0.01
0.24
0.09
O.Ob
0.02
0.06
0.03
0.01
0.06
0.03
0.01
0.2
0
0.12
0.7
0.03
11.1
1.3
0.03
3.1
1.3
0.8
1 .6
1.0
1.0
0.9
0.4
0.2
Nominal
(Low)
Amount
0
0.41
0.09
0.23
0.04
0.07
0.27
0.17
0.01
X of total
in U.S.
0
2.4
6.5
6.5
1.3
0.9
2. P.
1.8
0.1
0.01
0
0.01
0.03
0.001
0.02
0.05
0.002
0.14
0.03
0.02
0.006
0
0
0
0
0
0.1 0
0.1
0
0.06
0.33
0.02
0.2
0.66
0.04
1.8
0.3
0.2
0.4
0
0
0
0
0
0
Accelerated
(High)
Amount
0
0.75
0.16
0.41
0.04
0.13
0.48
0.74
0.01
% of total
in U.S.
0
4.4
12.0
12.0
1.9
1.7
5.0
7.7
0.1
0.02
0
0.01
0.07
0.001
0.03
0.10
0.01
0.24
0.09
0.04
0.02
0.06
0.03
0.01
0.06
0.03
0.01
0.2
0
0.12
0.7
0.03
0.4
1.32
0.1
3.1
1.3
0.8
1.8
1.6
0.6
0.9
0.4
0.2
0.1
O
-------
TABLE 55. ESTIMATED QUANTITIES OF SYNFUEL PRODUCTS USED IN THE U.S.: 1993-2000
Product
Crude shnle oil (fuel )
Shale oil refinery feed
Shole jet fuel
Shale dieoel fuel
Shale residuals
Shale gasoline
Medium I3tu gas (coal )
S:;G (coal)
Gasif icr tors, <.;i<,
Gasi Her phenol
F-T LPG
F-T ir.cdium Btu gas
F-T SI1G
F-T heavy fuel oil
F- F gasol ine
fi-gasol ine
F-T diesel fuel
Fuel niethanol
SPC II fuel oil
SKC 11 naphtha
SRC 11 LPG
EDS fuel oil
EDS naphtha
EOS LPG
H-coal fuel oil
H-coal naphtha
H-coal LPG
National Goal
(Modi urn)
Amount
(MMBPD)
0
0.13
0.09
0.23
0.04
0.07
0.29
0.50
0.01
0.02
0.003
U.UI
0
0.001
0.03
O.o
0.0005
0.23
0.09
0.05
0.02
0.06
0.03
0.01
0.03
0.03
0.01
i of
U.S.
0
2.1
6.8
6.8
1.3
0.9
3.0
5.2
0.1
U.2
0.03
0. 1
0
0.03
0.4
1.3
0.1
3.0
1.3
0.8
1.6
1.0
0.6
0.9
0.2
0.2
0.1
Nominal
(Low)
Amount
(MMBPD)
0
0.43
0.09
0.23
0.04
0
0.45
0.25
0.01
"L of
U.S.
0
2.4
6.8
6.8
1.3
0
4.7
2.6
0.1
0.0^
0
0.01
O.O/
o.om
0.03
0.1
0.01
0.23
0.09
0.05
0.02
0.06
0.03
0.01
0.06
0.03
0.01
0.2
0
O.I
0.7
0.03
0.4
1.3
0.1
3.0
1.3
0.8
1.6
1.0
0.6
0.9
0.4
0.2
0.1
Accelerated
(High)
Amount
(MMBPD)
0
0.75
0.15 1
',„ of
U.S.
0
4.4
2.0
0.41 12.0
0.04
0.13
0.48
0.74
0.01
1.9
1.7
5.0
7.7
0.1
' 0.02
0
0.48
0.07
o.om
o.m
0.1
0.03
0.?4
0.09
0.04
0.02
0.06
0.03
0.01
0.06
0.03
0.01
0.2
0
5.0
0.7
nm
04
1.3
0.4
3.1
1.3
0-8
1 .8
1.0
0.6
0.5
0.4
0.2
0.1
-------
regulatory and R&D activities does not have to await collection of
additional data, which should proceed concurrently as a separate activity.
6.2 Attribute Rating Procedure
Table 56 presents the assessment of the environmental concerns for
various synfuel products relative to their petroleum analogs on a
"barrel-per-barrel" basis. As indicated by the headings in the table, the
relative ranking considers potential for exposure, emission, and toxic
hazard, and the cost of control and the adequacy of existing regulations.
A (+) ranking is assigned to a product for an environmental attribute if
the product is judged to present greater environmental concern than the
petroleum analog; a ranking of (0) indicates that the environmental
concern would be similar to or less than that of the petroleum
product. Factors considered in assigning ratings to each product
for each environmental attribute along with some examples of product
ratings are presented below.
6.2.1 Exposure
Transport and Storage
This criteria considers the potential for environmental contamination
and public exposure resulting from releases caused by accidents, spills,
and fugitive emissions. As noted in Table 62, crude shale oil and the
direct liquefaction fuel oils have been assigned a (+) rating. These
products have been shown to contain higher amounts of water-soluble
compounds than their petroleum counterparts (References 46 and 47). In the
case of spills, this can result in a more rapid spread of pollutants and
more extensive contamination of the water environment than would be
expected from petroleum crude spills of similar size. Other products
listed in the table have been assigned a (0) rating because the very
limited currently available data do not indicate a higher potential for
exposure associated with transportation and storage, spills, and fugitive
emissions.
End Use
This criteria considers the potential for exposure associated with end
use (for example, exposure to combustion products or occupational
exposure). It is expected that synfuel products will be used in the same
manner as petroleum products. There appears to be no strong reason to
believe that exposure to the synfuel products would be any different than
exposure to the petroleum products. A (0) rating is assigned to all
products for this attribute category.
162
-------
TABLE 56. RELATIVE ASSESSMENT OF THE ENVIRONMENTAL HAZARDS ASSOCIATED WITH
SYNFUELS PRODUCTS AND PETROLEUM ANALOGS
Product
Crude shale oil (fuel)
Shale oil refinery feed
Shale Jet fuel
Shale dlesel fuel
Shale residuals
Shale gasoline
Low-/Med1um-Btu gas (coal)
SNG icoal
Gaslfler tars and oils
Gaslfler phenol
F-T LPG
F-T medium Btu
F-T SNG
F-T heavy fuel
F-T gasoline
M-gasollne
F-T dlesel fuel
gas
011
Fuel methanol
SRC II fuel oil
SRC II naphtha
SRC II LPG
EDS fuel oil
EDS naphtha
EDS LPG
H-coal fuel oil
H-coal naphtha
H-coal LPG
EXPOSURE
Transport
&
Storage
+
+
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
+
0
0
+
0
0
+
0
0
End Use
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
EMISSION
FACTOR
Transport
&
Storage
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
End Use
+
0
+
+
+
+
+
0
+
+
0
0
0
0
0
0
0
+
+
0
0
+
0
0
+
0
0
TOXIC
HAZARD
Transport
&
Storage
+
+
0
0
+
0
+
0
+
+
0
0
0
0
0
0
0
0
+
+
0
+
+
0
+
+
0
End Use
+
+
+
+
+
+
+
0
•f
+
0
0
0
0
0
0
0
0
+
+
0
+
+
0
+
+
0
COST OF
CONTROL
+
0
+
+
+
+
+
0
+
0
0
0
0
+
0
0
0
0
+
0
0
+
0
0
+
0
0
ADEQUACY OF
EXISTING REGULATIONS
CAA
+
0
+
+
+
+
+
0
+
0
0
0
0
0
0
0
0
+
+
0
0
+
0
0
+
0
0
CWA
+
+
0
0
+
0
0
0
+
0
0
0
0
0
0
0
0
0
+
+
0
+
+
0
+
+
0
RCRA
+
+
+
+
+
+
+
0
+
0
0
0
0
+
+
+
+
+
+
+
0
+
+
0
+
+
0
TSCA
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
CTt
CO
-------
6.2.2 Emission Factor
Transportation and Storage
This environmental attribute considers the amount of material that
would be released to the environment as a result of transportation and
storage activities, without regard to pollutant mobility and the number of
people potentially exposed {population density consideration). The
potential sources of release include primarily fugitive emissions and
spills. The limited data currently available on the characteristics of
synfuel products do not indicate higher volatility or greater potential for
accidental spills (see Section D.4, Appendix D). Accordingly, all synfuel
products have been given a "0" ranking for this environmental attribute.
End Use
End use emisssions include combustion emissions and evaporative
emissions assoicated with end uses (for example, use of gasoline in cars).
As indicated in Table 56 synfuel products that have been judged to present
greater end use emissions than petroleum analogs are shale oil products and
direct liquefaction fuel oils (because of higher NO emissions-see Table
47); low-/medium-Btu gas (because of higher emissions of trace elements and
heterocyclics); methanol (because of higher aldehyde emissions), and
gasifier by-products (if used as fuel). Because of their similar
volatilities, the use of shale oil as a refinery feedstock is expected to
result in quantities of fugiture emissions similar to those which would
result from the use of crude petroleum. Thus, a (0) rating has been
assigned to the use of shale oil as refinery feed.
6.2.3 Toxic Hazard
Transport and Storage
The toxic hazard criteria includes both human and ecological toxicity
considerations. The ratings shown in Table 62 are based on the results of
the various tests of biological activity discussed in Section 4.3 where no
actual test results were available, on the consideration of chemical
characteristics. The limited available test results indicate that the
toxicity of refined shale products is similar to that of their petroleum
counterparts. These products have been assigned a (0) rating. Because of
the presence of known toxic contaminants at levels higher than those in the
products they will displace in the market, low-/medium-Btu gas and gasifier
tars, oils, and phenols are assigned a (+) rating. The available test
results indicate that crude shale oil, shale residuals and direct
liquefaction fuel oils and naphthas are more toxic than their petroleum
counterparts. As shown in Table 56, these products have been assigned a
(+) rating. Examination of the chemical composition of the LPG's, SNG, and
indirect coal liquids reveals no reason to expect them to be more
biologically active than their petroleum counterparts; these products have
also been assigned a (0) rating.
164
-------
End Use
Most synfuels are expected to be used primarily as fuels in combustion
systems. Assessment of the known and estimated composition of many of the
combustion gases (see Tables 47 and 48, respectively) indicates that the
combustion products from crude shale oil and shale oil products, and from
low-/medium-Btu coal gas, gasifier tars, oils, and phenols, and direct
liquefaction fuel oils would be more toxic than the combustion products
from their petroleum-derived counterparts. When used as feedstocks, shale
oil and direct liquefaction naphthas are expected to pose greater toxic
hazards than petroleum crudes and naphthas. Medium-Btu gases and gasifier
tars, oils, and phenols, if used as feedstocks rather than as fuels, are
also expected to pose greater toxic hazards than currently used feedstocks.
Accordingly, all of these synfuels have been assigned (+) ratings. The
remaining products in Table 56, which would be used primarily as fuels, are
not expected to produce more toxic combustion gases than their
petroleum-derived counterparts. Because little is known about the effects
of chronic exposure to low levels of methanol (levels below those which are
known to produce acute symptoms) and the health effects characteristics of
methanol combustion products, it is very difficult to assess the toxic
hazards associated with the use of methanol as fuel relative to the use of
petroleum gasoline. Combustion of methanol has been shown to produce
higher amounts of aldehydes but lesser quantities of other potentially
hazardous substances such as PNA's; therefore, the overall health effects
of methanol relative to petroleum gasoline cannot be judged based solely on
the available data on compositon of combustion products. Because of these
uncertainties a ranking of (0) has been assigned to methanol.
6.2.4 Cost of Control
The cost-of-control attribute has been rated primarily on the basis of
added control costs for regulated pollutants wherever such pollutants (NO
especially, and occasionally particulate and SO ) are anticipated to be
emitted at levels exceeding those from the combustion of petroleum products
for synthetic fuel use. Much more information will be needed on combustion
pollutants and associated solid and liquid wastes (for example, particulate
collection, storage tank aqueous sludges) to update these ratings. For
example, the replacement cost frequency for automobile catalytic converters
could be significantly increased if trace synthetic gasoline constituents
such as arsenic result in rapid catalyst deactivation. Based on these cost
considerations, a rating of (+) has been assigned to shale oil products
(used as fuel), low-/medium-Btu gas, gasifier tars and oils, and direct
liquefaction fuel oils.
6.2.5 Adequacy of Existing Regulations
The rating under this category is broken down under the grouping of
regulations established under the authority of the major environmental
legislation that could affect synfuel product utilization (see Section
5.3.2 for a review of key pertinent legislation). A (+) entry implies that
a greater amount of regulatory protection will probably be needed than is
165
-------
now available through existing or near-term regulations, relative to
petroleum product or natural gas use. A (0) entry implies that existing
regulations offer the same protection as now achieved with petroleum
product.
Clean Air Act (CAA)
As noted in Section 5.3.2, most of the existing and planned air
quality protection regulations focus on criteria pollutants (that is, SO ,
NO , CO and particulate matter) or on classes/categories of substances (for
example, volatile organic carbon). Although very important in air quality
protection, these criteria do not address specific hazardous components of
pollutant categories included in the standards (for example, polycyclic
organic matter in the particulates) or other hazardous substances that
might be emitted. This limitation of the existing air pollution control
regulations applies to both synfuel and petroleum products end uses, ".
although to different degrees. The relative severity of this limitation
and therefore the greater need for regulatory protection has been the basis
for the ranking shown in Table 56- As indicated in the table, a ( + )
ranking has been assigned to shale oil products (used as fuel),
low-/medium-Btu gas, gasifier tars and oils, fuel methanol, and direct
liquefaction fuel oils. These products have been assigned (+) ratings
because of possible emissions of higher amounts of toxic substances
(hazardous trace elements associated with the particulates emitted in the
combustion of shale oil products and low-/medium-Btu gas; emissions of
higher amounts of PNA's with synfuels that are generally richer in
aromatics).
Clean Water Act (CWA)
The objective of the Clean Water Act is to regulate point source
discharges into navigable waters. Effluent discharges from synfuel storage
and using industries would be subjected to effluent guidelines for point
source industrial discharges. Under the provisions of the Act, effluent
controls using the best available technology economically achievable
(BATEA) would be required for the control of some 65 substances/classes of
substances, commonly referred to as priority or "Consent Decree"
pollutants. EPA is to promulgate and apply BATEA standards for industrial
point source categories by July 1, 1984. The priority pollutants include
some of the hazardous substances (benzene, phenol, arsenic, and
ethyl benzene) that are expected to be present in wastewaters from plants
using synfuel products, as the result of direct product uses or accidental
spills. Because of the lack of data on the characteristics of the
166
-------
wastewaters from such plants* and on the capabilities and costs of
applicable control technologies, it is very difficult to predict the
adequacy of the yet-to-be promulgated BATEA standards for the control of
effluent discharges from synfuel storage/using industries.
Because of these uncertainties, the assessment of the relative degree
of regulatory protection provided under the Clean Water Act for synfuel vs.
petroleum products storage/using facilities has been based primarily on the
consideration of the known or expected differences in the characteristics
of synfuel products relative to their petroleum analogs. It is thus
assumed that the differences in product characteristics would be reflected
in differences in the wastewaters, which would in turn affect the adequacy
of BATEA in providing equal protection. Based on these considerations, the
following products have been assigned a ( + ) ranking: crude shale oil (fuel
and refinery feedstock), shale residuals, gasifiers tars and oils and
direct liquefaction fuel oils and naphthas.
Resource Conservation and Recovery Act (RCRA)
Utilization of synfuel products would produce solid wastes in the form
of sludges from storage tanks and cleaned-up spill material and, in some
cases, solid wastes and sludges from air pollution control. Although these
wastes are not presently included in the list of "specific" hazardous waste
developed by EPA pursuant to RCRA, the wastes would most likely be
designated as hazardous based on other RCRA criteria (for example,
containing specific chemicals listed as toxic materials see Section
5.3.2). Effort to develop hazardous waste management regulations pursuant
to RCRA is still in progress and data on the characteristics of synfuel
utilization wastes are currently unavailable; accordingly, in Table 56 the
indicated assessment of the relative degree of regulatory protection
provided under RCRA for synfuel vs. petroleum products utilization wastes
primarily reflect judgment as to the relative hazards posed by the two
waste categories, based on known or expected differences in the
characteristics of synfuel products relative to their petroleum analogs.
As noted in Table 56, a (+) ranking has been assigned to shale oil
products; gasifiers, tars, oils and phenols; direct liquefaction fuel oils
and naphthas; and low-/medium-Btu gas. Hazardous solid wastes resulting
from air pollution control would result from the use of low-/medium-Btu gas
as fuel.
The characteristics of wastewater from a plant using synfuels (for
example, a petroleum refinery that uses crude shale as part of its
feedstock) would be affected by several factors including chemical
characteristics of the specific synfuel product used, the extent of
blending/usage (for example, in the case of refinery handling shale oil,
the amount of shale oil as a percentage of total refinery feed),
refining/processing steps used,and in-plant water conservation and waste
minimization/management practices.
167
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Toxic Substances Control Act (TSCA)
As noted in Section 5.3.2, EPA's approach to the regulation of synfuel
products under TSCA is still being formulated. Under the mandate of TSCA,
many of the synfuel products would fall into the "new products", "new
uses", or "products produced using different processes" categories and
would be subject to pre-manufacturing notification provision of TSCA. At
the present time, a key point of uncertainty relates to whether for synfuel
products, the assessment of "unreasonable risks", which is the basis for
product regulation under TSCA, should be in "absolute" terms or in terms of
product properties relative to those of existing and widely used petroleum
products.
The assessment of the relative degree of regulatory protection that
would be provided by TSCA for synfuel vs. petroleum products requires
resolution of the previously mentioned uncertainties. Strict
interpretation of the TSCA mandate to regulate substances that present
"unreasonable risks" to health and the environment would suggest that
regulatory protection provided under TSCA for synfuel products (as well as
petroleum or other products of commerce) should be adequate. Because of
this and the regulatory uncertainties, a ranking of (0) has been assigned
to all products in Table 56 in connection with the adequacy of TSCA
regulations.
6.3 PRODUCTS RANKING
Table 57 presents the results of synfuel products ranking. The
products are ranked into three groups: those eliciting the most concern
(ranked as 1), those indicating modest concern (ranked as 2) and those
generating a low level of concern at the present time (ranked as 3). As
noted in the table, in the near term (1980-1987 period), synfuel products
of concern are primarily the shale oil products and medium-Btu gas and SNG
from coal gasification. Under the nominal scenario, shale oil refinery
feed elicits the most regulatory attention, other shale oil products and
medium-Btu gas elicit modest concern, and SNG requires low level of
attention. Except for a ranking of 1 for direct use of crude shale oil as
fuel under the national goal and accelerated scenarios, the rankings remain
the same under the three production scenarios during 1980-1987.
For the 1988-1992 period, when products from SRC II and F-T processes
will also be marketed, the products eliciting most concern would consist of
shale oil refinery feed, fuel methanol, SRC II fuel oil, gasifier tars and
oils, and medium-Btu gas (under national goal and accelerated scenarios).
F-T products and LPG from SRC II are ranked as low priority products during
1988-1992. During the 1993-2000 time frame, shale oil refinery feed,
medium-Btu gas (under nominal and accelerated scenarios), gasifier tars and
oil, and fuel oils from the three liquefaction processes are ranked as 1,
F-T products are assessed as 3, and all other products are given a 2
ranking.
168
-------
TABLE 57. PRIORITY RANKINGS OF SYNTHETIC FUEL PRODUCTS
Product
Crude shale oil (fuel )
Shale oil refinery feed
Shale jet fuel
Shale diesel fuel
Shale residuals
Shale gasoline
Medium Btu gas (coal)
SNG (coal)
Gasifier tar
Gasifier oils
Gasifier phenol
F-T LPG
F-T medium Btu gas
F-T SNG
F-T heavy fuel oil
F-T gasoline
M-gasoline
F-T diesel fuel
Fuel methanol
SRC II fuel oil
SRC II naphtha
SRC II LPG
EDS fuel oil
EDS naphtha
EDS LPG
H-Coal fuel oil
H-Coal naphtha
H-Coal LPG
1980-1987
National
Goal
1
1
2
2
2
2
2
3
-
-
2
-
-
-
-
-
-
-
-
_
-
-
_
-
-
_
-
—
Nominal
2
1
2
2
2
2
2
3
-
-
2
-
-
-
-
-
-
-
-
_
-
-
_
-
-
_
-
•~
Accelerated
1
1
2
2
2
2
2
3
-
-
2
-
-
-
-
-
-
-
-
_
-
-
_
-
-
_
-
~
1988-1992
National
Goal
1
2
2
2
2
1
-
1
-
2
-
3
3
3
3
3
3
1
1
2
3
_
-
-
_
-
~
Nominal
1
2
2
2
2
2
-
1
-
2
-
3
3
3
3
3
3
1
1
2
3
_
-
-
_
-
—
Accelerated
1
2
2
2
2
1
-
1
-
2
-
3
3
3
3
3
3
1
1
2
3
_
-
-
_
-
—
1993-2000
National
Goal
1
2
2
2
2
2
-
1
_
2
_
3
3
3
3
3
3
1
1
2
2
1
2
3
1
2
3
Nominal
1
2
2
2
2
1
3
1
_
2
_
3
3
3
3
3
3
1
1
2
2
1
2
3
1
2
3
Accelerated
1
2
2
2
2
1
-
1
_
2
_
3
3
3
3
3
3
1
1
2
2
1
2
3
1
2
3
CT)
— Indicates product is not produced under the scenario shown
Degree of Concern: riost = 1, Modest = 2, Low = 3
-------
The rankings presented in this section generally indicate the greatest
level of environmental concern and regulatory requirements for shale oil
refinery feed and coal liquids. As discussed in Section 5, these liquids
have been demonstrated to be more hazardous than petroleum crude and fuel
oils (a major factor in assigning a 1 ranking). This, and the fact that
shale oil products will be the first synfuels that are expected to enter
the market on a large scale are the major factors that signify near-term
environmental concerns for shale oil products in general and shale oil fuel
and refinery feed in particular.
170
-------
SECTION 7
DATA GAPS AND LIMITATIONS AND RELATED PROGRAMS
As noted previously, a number of major gaps in the existing data base
preclude accurate analysis of the potential environmental concerns
associated with a future large scale commercial synfuel industry in the
U.S. and of applicable controls and mitigation measures. These data gaps
and limitations relate to (a) present uncertainties regarding the size of
the industry, specific synfuel technologies that will be used, locations of
production facilities and product distribution systems, and the specific
areas of synfuel use; and (b) lack of adequate characterization data on
synfuel products and on the analogous petroleum products that they will
partially or totally replace. The first category affects the regional
environmental implications and synfuel production scenarios and market
analyses developed in Sections 2 and 3 of this report, whereas the second
category introduces uncertainties in the estimated characteristics of
synfuels products (Section 4) and the analysis of environmental concerns
(Section 5). Both types of data limitations impact the regional
environmental implications and the priority ranking of the synfuel
products.
This section examines the major factors responsible for data gaps and
limitations, summarizes the data gaps and limitations, and lists some of
the on going and planned programs that are expected to generate some of the
needed data for a more refined analysis of the environmental implications
of large-scale utilization of synfuel products.
7.1 MAJOR FACTORS RESPONSIBLE FOR DATA GAPS AND LIMITATIONS
The limitations of the available data stem from a large number of
factors, most important of which are the following:
• The present uncertainties surrounding the U.S. energy policy and
changing domestic and international political conditions that
impact oil and natural gas supplies and prices.
These uncertainties make it extremely difficult if not impossible
to develop reasonably accurate forecasts of the extent of the
contribution of synfuels to the near-term energy picture in the
U.S.
171
-------
Synfuel production processes are still evolving and will be
continuously modified and refined before optimum technologies anc
specific designs and equipment are selected for use in
large-scale commercial facilities. In the U.S., synfuel pilot
plants and experimental units that have been operated or are
currently in operation have been designed and operated primarily
to develop design criteria and process optimization with little
emphasis on product characterization from an environmental
standpoint or on definition of optimum conditions for production
of environmentally acceptable products. Thus, the
characteristics of the products from pilot-plant operations may
not accurately reflect those of products that would be produced
in large-scale installations.
Some synfuel processes have been used commercially abroad; these
commercial facilities do not generally incorporate the design a^:
operating features that would likely be used in U.S. facilities
to minimize pollutant generation and improve the environmental
acceptability of products. Moreover, the coals used at these
facilities differ from those that will be used at commercial
synfuel plants in the U.S. Because of these reasons, the
available product characterization data frou commercial
installations abroad may not adequately reflect the anticipated
characteristics of products from consiercial plants in the U.S.
Most of the process test and evaluation and product
characterization efforts to date have been in connection with the
production of prisary synfuels (that is, shale oil,
low-/Bediuet-Btu gas, SNG, and coal liquids); very little effort
has been expended to evaluate the refining of synfuels and the
subsequent production and characterization of secondary products
[synfuel-derived naphtha, gasoline, solvents, etc.).
Although oany of the environmental pollution controls and
aitigation measures that would be used in connection with
production, distribution, and use of synfuel products have been
used successfully in other industries and in connection with
petrol sura based products, they have not been evaluated
specifically on synfuel products and their effectiveness in sycfc
applications renains to be evaluated.
A significant portion of the synfuel process developaent efforts
and the testing of the synfuel products is being carried out by
private industry. Much of the data that Hay exist for these
processes and the characteristics of their products is considers
proprietary and is not publicly available.
For those synfuel processes for utiidh soese product
characterization data are available, such data are not
comprehensive in that not all products and characteristics of
environoental interest are addressed.
172
-------
• Even though there has been a long standing Interest in the
extraction of oil from oil shale and the conversion of shale oil
and coal to liquids and gaseous fuels, and although a number of
synfuel facilities have been in operation for some time in other
countries, it is only very recently that there has been a very
strong interest in assessing the environmental aspects of
synfuel technologies. The present study appears to constitute a
first attempt to focus attention on the potentially broad
environmental implications of large-scale marketing and
utilization of synfuel products.
• Because of the large-scale and widespread use of petroleum
products, these products have generally come to be viewed by the
public as environmentally innocuous. Accordingly, the
specifications for petroleum products have primarily emphasized
performance with little attention to environmental
considerations. Very little data are available on potential
pollutants and toxicological and ecological properties of many of
the petroleum products to provide a baseline for assessing the
relative safety of synfuel products.
7.2 SPECIFIC DATA GAPS AM) LIMITATIONS
In general, the data gaps and limitations fall into two categories:
(1) relevant data that are totally nonexistent or unavailable and (2) data
that are available but lack comprehensiveness, or have been obtained under
conditions significantly different than those anticipated in large-scale
production operations and product marketing and distribution systems in the
United States. Examples in the first category are the lack of data on the
concentration of coal-derived impurities in synfuel products (for example,
LPG and solvents and the cheaical feedstocks that will be used in industry
and coBoerce), on the characteristics of sludges from synfuel products
storage facilities, and on the effectiveness and service life of
conventional control technologies and mitigation measures (for example,
catalytic converters in autoaobiles) in synfuel service. These data gaps
result froa the fact that many of the synfuel products have not yet been
produced on a coraiercial scale and large-scale distribution, service
networks, and use patterns have not yet been established for thea. Even
though certain product characteristics can be estimated through engineering
studies based on process engineering considerations and the knowledge of
the input materials, such studies have not been conducted for the aajority
of synfuels products, especially those produced further "downstreao". For
sane products for which saee data night exist (for exaople, EDS direct
liquefaction process), such data are not publicly available because they
are proprietary.
Exaaples of the second category of data gaps are the lack of trace
elenent and toxicological and ecological information for many of the
synfuels products, their petroleum analogs, and emissions froa their
combustions. Where sane data are available, such data do not cover
173
-------
detailed composition and types and levels of trace elements and
coal-derived impurities, long-term bioassay and health effects information,
biodegradability and potential for environmental persistence.
Because large-scale synfuel production facilities do not currently
exist, the first category of data gaps can only be partially filled, for
example, through engineering studies, at the present time. Many of the
gaps in the second category, however, can and should be filled through
multimedia environmental sampling and analysis of the products and
process/discharge streams at pilot plants and commercial foreign synfuels
facilities and through product testing and evaluation programs (for
example, combustion testing of fuels). Even though pilot plants and test
and evaluation units may not be scalable to or representative of commercial
facilities and applications, sampling at pilot plants and test and
evaluation studies represent the best and the only means of acquiring
meaningful data on product characteristics and on the effectiveness of
various controls. Such sampling and analysis, coupled with product testing
and evaluation, can provide valuable and timely inputs to the evolution of
the synfuel industry and would ensure that; (1) environmental considerations
are included in the selection of processes, equipment, and waste .management
options for commercial facilities, and (2) the drafting of specifications
for synfuel products, new source performance standards for synfuel plant
and emission standards for facilities using synfuel products are based on
the best available technical and engineering data. Several currently
underway or planned programs involve sampling at pilot plants, bench-scale
units, or foreign commercial synfuel facilities; environmental
characterization of synfuel products; and testing and evaluation of certain
uses of synfuel products. The more important of these and related
engineering studies are summarized in Section 7.3.
7.3 RELATED PROGRAMS
Major programs that are expected to generate some of the data needed
for environmental assessment of synfuel product utilization fall into
several categories, including EPA-sponsored programs, DDE-sponsored
programs, programs carried out by other agencies such as the Department of
the Navy and the Tennessee Valley Authority, programs carried out by
developers and product users, and programs carried out in connection with
commercial synfuel projects. The Fossil Fuels Research Materials (FFRM)
facility was recently established between the U.S. EPA and DOE to provide
support for health and environmental effects studies for the generation of
some of the data needed for environmental assessment of synfuel
technologies. The data collected by process developers and major potential
users of synfuels are considered company proprietary and are not made
public. In connection with the requirements for the preparation of
environmental impact assessments, the sponsors of major commercial synfuel
projects collect certain product characterization data and analyze
environmental concerns and alternative mitigation measures on regional and
local levels. Major commercial coal liquefaction and gasification projects
and cooperative agreements and feasibility study grants for synfuels are
listed in Appendices B and C, respectively. The most relevant of the
174
-------
government funded programs, especially those most directly related to the
characterization of synfuel products from the standpoints of environmental
health effects and combustion emissions, are reviewed briefly in the
following paragraphs.
7.3.1 Environmental and Health Effects Programs
Tables 58 and 59 summarize the chemical and biological/ecological
tests currently being conducted by EPA and DOE laboratories and by other
government and private agencies, such as the U.S. Navy, the American
Petroleum Institute, and several universities, on various samples of shale
oil and coal liquefaction products. As indicated in the tables, the
products are undergoing a fairly comprehensive chemical analyses as well as
a battery of bioassays including small animal carcinogenicity,
tumorigenicity, acute oral toxicity, and bacterial mutagenicity. Results
of the testing are just beginning to be obtained and have not yet been
released.
In addition to the studies shown in Tables 53 and 59 large-scale
toxicological and combustion studies are also being conducted independently
by the U.S. Navy on oil shale products. The products being studied include
DFM (acid pretreat), final JP-4, JP-5, JP-8 products, and final DFM
product. Tests being conducted include acute oral toxicity, acute
inhalation toxicity, acute dermal toxicity, skin and eye irritation
studies, skin sensitization studies, subacute dermal toxicity, chronic
inhalation toxicity, and behavioral toxicity.
Biomedical screening studies of SRC II syncrude and petroleum
materials are also being conducted by DuPont. To date, Ames mutagenicity
testing and mouse skin paintings have been conducted on SRC II fuel oil
blends of 2.9:1 middle-to-heavy distillate. Results of these tests have
not yet been made public.
Most of the current chemical and biological/ecological testing of coal
gases involve low-/medium-Btu gasification products rather than SNG. The
Morgantown Energy Research Center and the Lovelace Inhalation Toxicology
Research Institute are currently conducting toxicological evaluations of
effluents and process streams from low-Btu gasifiers. Results of these
studies have not yet been released.
Studies pertaining to high-Btu gasification are being carried out by
DOE and EPA. DOE has recently undertaken a program for the biological and
toxicological characterization of process and product streams from the
Hyqas and other SNG pilot plants. Results are not available from the
program, which is being conducted at Argonne National Laboratory and
several other DOE laboratories.
7.3.2 Combustion Characteristics
The performance of middle and heavy distillates, fuel oil blends, and
3:1 middle-to-heavy distillates from the SRC II pilot plant is currently
175
-------
TABLE 58. CHEMICAL, BIOLOGICAL AND ECOLOGICAL TESTING OF PARAHO/SOHIO CRUDE
AND REFINED SHALE OIL SUITE
01
RESEARCH
MATERIAL
Crude Shale Oil
HOT Shale Oil
Weathered Gas
Feedstock
JP-5 Precursor
JP-8 Precursor
DFM Precursor
HOT Residue
JP-5 Product
JP-8 Product
DFM Product
Acid Sludge
Petroleum JP-5
Petroleum JP-8
Petroleum DFM
Chemistry
Ol
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Key to Investigators
1. L. W. Burdett, Union Oil Co.
(API Sponsored)
2. S. C. Blum, Exxon (API Sponsored)
3, W. Berkley, Kettering Laboratory
4. J. H. Holland, ORNL
5. L. M. Holland, LASL
6. o. L. Epler, ORNL
7. F. T. Hatch, LLL
8. S. Zimmering, Brown University
9. M. Legatur, University of Texas
10. H. P. l/itschi, ORNL
11. J. H. Giddings, ORNL
12. D. L. Coffin, EPA
13. J. H. Dumont/T.W. Schultz, ORNL
14. N. Richards, EPA
15. «. H. Griest, ORNL
16. B. R. Clark, ORNL
17. L. Smith, ORNL
18. M. Pepelco, EPA
-------
TABLE 59. HEALTH EFFECTS TESTING FOR DIRECT COAL LIQUIDS(45)
Coal Liquids
eratogenesis
ral Toxicity-Rat
ral Toxi city-Mouse
1— O O
SRC II Fuel Oil Blend 1 - 2
SRC II Heavy Distillate 10 10
SRC II Middle Distillate 10 10 11
SRC II Light Distillate 10 10
EDS Coal Liquids ...
H-Coal Liquids 1
SRC I 1 - -
Key to Investigators
1 N. Klein, University of Connecticut
2. H.P Witschi, ORNL
3 S Zimmering, Brown University
4. M Legatur, University of Texas
5. J. M. Giddings, ORNL
6. N Richards. U.S. EPA
7. J.M. Holland, ORNL
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.
8 J. L. Epler, ORNL
9. A.P Pfuderer, ORNL
10. Battelle Memorial Institute, Richard
11. Eartlesville Energy Technology Center
12. W.H. Calkins, du Pont
13. J.N. DuMont, J.W. Schultz, ORNL
14. R. Milliman, ORNL
-------
being studied by the Pittsburg Energy Technology Center. Results of this
study have not yet been made available.
No studies are currently underway for the characterization of
combustion products of indirect coal liquids. However, it 1s likely that
performance characteristics of Mobil-M and Sasol products are continuing to
be studied by their respective developers.
TVA, in conjunction with EPRI, Radian, and TRW, is currently
sponsoring a program for the environmental assessment of waste streams
associated with low-/medium-Btu gasification. Although the objectives of
the TVA program do not include product or product combustion
characterization per se, EPA is expected to participate in the program at a
future data in order that bioassays of waste stream and possibly
products/by-products be performed. To date, the TVA program has included
sampling and analysis activities at the Ruhr-Chemie gasification facility
in Germany involving a Texaco gasifier and the testing of an Illinois basin
coal. Testing of another Illinois coal at a Kopper-Totzek facility in
Greece is planned for late February.
178
-------
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1980.
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180
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Capacities - Gas Pipeline, Vol. VI, December 1979.
32. U.S. Department of Energy, Petroleum Supply Alternatives for the
Northern Tier and Inland States Through the Year 2000, Vol. I,
October 31, 1979.
33. Energy Information Administration, State Energy Data Report,
April 1980.
34. National Petroleum Council, Petroleum Storage and Transportation
Capacities - Pipelines, Vol. Ill, December 1979.
35. Synfuels, September 12, 1980.
36. Information provided to TRW by Robert Garbe, U.S. EPA, Ann Arbor,
Michigan, January 16, 1981.
37. M. Ghassemi, K. Crawford and S. Quinlivan, Environmental
Assessment Report: Lurgi Coal Gasification Systems for SNG,
EPA-600/7-79-120, May 1979.
38. M. Ghassemi, K. Crawford and S. Quinlivan, Environmental
Assessment Data Base for High-Btu Gasification Technology, Vols
I-III, EPA-600/7-78-186a, September 1978.
39. R.J. Young, Potential Health Hazards Involved with Coal
Gasification, PHEW (NIOSH) Technical Report, No. 79-113,
Cincinnati, Ohio, November 1978.
40. NIOSH Criteria for a Recommended Standard, Occupation Exposures
in Coal Gasification Plants, DHEW (NIOSH) Technical Report No.
78-191, Cincinnati, Ohio, September 1978.
41. M. P. Kilpatrick, et al., Environmental Assessment: Source Test
and Evaluation Report - Wellman-Galusha (Ft. Snelling) Low Btu
Gasification, EPA-600/7-80-097, May 1980.
42. Information provided to TRW by R. Dwyer, Illinois State
Geological Survey, Urbana, Illinois, January 22, 1981.
43. TRW Energy Systems, Carcinogens Relating to Coal Conversion
Processes, Final Report, Contract No. E(49-18)-2213.
181
-------
44. Information provided to TRW by Dr. William Lloyd, OSHA, December
22, 1980.
45. Hazardous Materials Management Journal, May-June 1980.
46. Giddings, J.M. and J.N. Washington, Coal Liquefaction Products,
Shale Oil, and Petroleum. Acute Toxicity to Freshwater Algae.
Environmental Science and Technology, Volume 15 (No. 1).,
106-108, January 1981.
47. Giddings, J.M., et al., Toxicity of a coal Liquefaction Product
to Aquatic Organisms, Bull. Environmental Contam., Toxicol., Vol
25, 1-6, 1980.
48. W.H. Griest, D.L. Coffin and M.R. Guerin, Fossil Fuels Research
Matrix Program, ORNL/TM-7346, June 1980.
182
-------
APPENDIX A
INTERVIEWS WITH POTENTIAL
SYNFUEL SUPPLIERS AND USERS
TABLE OF CONTENTS
PAGE
A.I Expected Involvement in Synfuel Industry ....... A-2
A. 2 Synfuel Products Market ................ A-2
A. 3 Significant Factors Impacting the Synfuel Industry . . A~4
A. 4 Anticipated Period of Time to Buildup, Establish
a Commercial Synfuel Industry ............. A-4
A. 5 Synfuel Products Compared to Petroleum-Based
Products ...................... A-4
A. 6 Anticipated Modifications to Facilities or
Procedures for Marketing Synfuel Products ....... A-5
A. 7 Awareness of Environmental Issues Relating to
Synfuel Utilization .................. A-6
SUPPLIERS
USERS
Exxon Company, USA A-7
TOSCO A-15
Shell Oil Company A-18
American Petroleum Institute A-20
General Motors A-25
A Major Chemical Company A-23
Department of Navy A-29
Electric Power Research Institute A-32
A-l
-------
A limited series of interviews were conducted with potential suppliers
and users of synfuel products to sample firsthand the views and projections
of industrial players in the synfuels market. Participating firms and
organizations are listed in Table A-l. Interviews were conducted at the
firms' locations. A set of standard issues was covered at each interview.
The responses of each participant are summarized later in this Appendix.
The general conclusions and some of the significant points made by the
participants are broadly outlined here.
A.I EXPECTED INVOLVEMENT IN SYNFUEL INDUSTRY
The suppliers generally indicated a broad interest in synfuel
technologies because all resources (oil, coal, shale) are limited and each
may have constraints to full development so all potential supply
technologies must be constantly assessed.
Those technologies that produce products most similar to existing
products or are most easily adapted to the present production, marketing,
and utilization systems are most favored. In general, shale oil was
thought to be most nearly cost competitive and commercial. Crude shale oil
will be upgraded and hydrotreated to yield a desirable refinery feedstock.
For the foreseeable future, existing refinery capacity will be used for any
shale oil production.
Medium-Btu gas from coal is thought to be cost competitive with higher
priced imported gas. High-Btu gas (SNG) and coal liquids are generally
projected as longer-term potential supplies. Synfuel plants will be
located near resources; refineries will be located as they traditionally
are—near sources of supply and users.
A.2 SYNFUEL PRODUCTS MARKET
In general, two major trends appear to be impacting the markets that
synfuel products may enter. The demand for gasoline appears to be
declining because of improved vehicle efficiency, conservation and
penetration of diesel fuel. For the liquid fuels, the middle distillates
(diesel and jet fuel, home heating oil) will drive the liquid synfuels
market over the next few years. The need to find an alternative to oil as
a boiler fuel, and the need to secure long-term supplies of chemical feed-
stocks have generated a great deal of interest in medium-Btu gas supply
technologies.
Both suppliers and users view shale oil as a potential premium
refinery feedstock — ideal for production of middle distillates. Initially,
the shale oil will be marketed to refineries in the Rocky Mountain region
until most of the spare refinery capacity is utilized. The next market to
develop will be the Midwest, which is projected to have a significant (up
to 300,000 BPD) spare capacity over the next 20 years.
The likely uses of medium-Btu gas will be in plants that produce
chemical feedstocks and fuel gas for onsite (or nearby) use and in electric
utility combined cycle plants.
A-2
-------
TABLE A-l. INTERVIEWS WITH POTENTIAL SYNFUEL SUPPLIERS AND USERS
Suppliers
Expected Synfuel Market Participation
i
CO
Exxon Company, USA
Houston, TX
*TOSCO
Los Angeles, CA
Shell Oil Company
Houston, TX
American Petroleum Institute
Washington, D.C.
Users
General Motors
Warren, MI
A Major Chemical Company
Actively developing shale oil, coal gasification
and coal liquefaction.
Supplier of shale oil feedstock to refiners.
Coal gasification; some interest in oil shale.
Representative of petroleum industry interest.
Liquid transportation fuels, primarily hydrocarbons.
Gaseous and liquid feedstocks for chemical industry.
Department of Navy
Washington, D. C.
Electric Power Research Institute
Palo Alto, CA
Liquid fuels for military equipment; airplanes, ships,
Gaseous and
fuels for utility boilers.
Telephone interview
-------
Coal liquids will probably impact the market for heavier fuels--
stationary turbines, special diesels, and, potentially home heating oil.
(If medium-Btu gas is successful, use of coal liquids as a boiler fuel may
be limited.) Methanol from coal is viable as a technology, but there is no
marketing infrastructure to handle this product.
A.3 SIGNIFICANT FACTORS IMPACTING THE SYNFUEL INDUSTRY
• Costs of synfuel products versus petroleum and gas.
t Availability of supplies. The need for a secure supply of
transportation fuels by the military, the need for long-term
supplies of chemical feedstocks by some industries, the general
decline in the petroleum resource, the uncertainty in import
supplies.
• Changing market patterns and trends (see A.2 above).
t Government participation. The SFC and creation of incentives are
necessary but regulations will produce uncertainty and hinder
development.
A.4 ANTICIPATED PERIOD OF TIME TO BUILDUP AND ESTABLISH A COMMERCIAL
SYNFUEL INDUSTRY
The consensus response of the suppliers was that the total synfuel
market may develop less rapidly than the national goal plan; the rate of
development will probably be closer to the nominal scenario described in
Section 3. The consensus places total production at 1.0 to 1.5 MMBPD by
1990. The suppliers indicated plans for commercial readiness for non-oil
shale technologies within the next three to five years.
The major factors impacting the buildup rate include the degree of
government support and the effect of environmental attitudes towards
industry, especially regarding the Clean Air Act and water regulations.
A.5 SYNFUEL PRODUCTS COMPARED TO PETROLEUM-BASED PRODUCTS
In general, the suppliers take the view that there will be no
discernable or significant differences in the refined liquid products
produced from synfuels compared to products from petroleum or natural gas.
These products from synfuels will be produced to specifications by using
conventional, well-known processes. This naturally leads to the consensus
among suppliers that no additional or special concerns are warranted
regarding synfuel products markets. Some specific points follow:
• For shale oil, there are no compositions unique to shale oil
compared to petroleum. The physical and chemical characteristics
of synfuel products will be essentially the same as those from
refined petroleum products. The products are processed to
specifications and the users will identify no differences.
A-4
-------
• Concerning the industry's ability to process shale oil (and coal
liquids) to acceptable specifications, it is pointed out that
crude petroleum, as derived from various locations, exhibits a
range of compositions that brackets oil shale. Unacceptable
quantities of nitrogen, sulfur and arsenic are removed by
upgrading, hydrotreating, or other processing steps. This
additional processing or upgrading is a matter of economics. The
trend in the U.S. is to upgrade the heavy residuals. Some of the
technologies developed for this purpose can be used in the
processing and refining of synfuels.
The users, on the other hand, supplied varying responses to
identifying differences between liquid synfuels and conventional
products.
• While users expect the suppliers to produce synfuel products to
specifications, it is not clear that the current specifications
are sufficient to guarantee performance and environmental
acceptability. For example, severe hydrotreating may destroy or
alter certain characteristics of fuels (e.g., lubricity) so that
trade-offs in processinq to remove contaminants versus
preservation of performance may limit the degree of additional
processing.
• Of the synfuel products being considered, coal liquids, if used
directly, are perceived as most different from conventional
products regarding toxicity and composition.
The users interviewed are generally involved in tests of various
synfuel products for both performance and potential environmental
impacts. These tests are expected to determine the degree of
additional processing required and the acceptability of synfuel
products.
A.6 ANTICIPATED MODIFICATIONS TO FACILITIES OR PROCEDURES FOR MARKETING
SYNFUEL PRODUCTS
From the suppliers' viewpoint, no special facilities or procedures are
anticipated for the distribution, handling, or storage of synfuels. In
general, products will be processed to specifications and no problems over
and above marketing of conventional products are expected. Coal liquids,
with their highly aromatic contents, are a possible exception and need to
be studied.
The users generally see a need for some modification of end use
devices. Engines and combustors must be modified to use the synfuels
efficiently and cleanly. The users view the process of synfuel product
acceptance as one of interaction between users' needs and the costs and
capabilities of additional processing by suppliers. For example, transpor-
tation fuels are usually qualified or tested for such characteristics as
sulfur, nigrogen, trace elements, aromaticity, volatility, octane quality,
A-5
-------
and long-term materials compatibility. The fuel-bound nitrogen in shale
oil-derived fuels may prove not to affect engine performance at all for
nitrogen levels yielding emissions of"1.2 grams per mile, but it may turn
out to be too costly to process fuel to meet a standard of 1.0 grams per
mile.
Because of the large capital investment, users' consensus is that very
few modifications to end use equipment will actually take place over the
next 20 years; the primary path to acceptable synfuel use will probably be
through refining and processing.
A.7 AWARENESS OF ENVIRONMENTAL ISSUES RELATING TO SYNFUEL UTILIZATION
In general, the suppliers expect to produce most products to
specifications such that no environmental problems over and above those
present in the marketing of conventional products will be encountered.
Some specific points follow:
• Tests indicate that shale oil has the same potential carcinogen-
icity as some conventional industrial fuels currently in use.
Polycyclic aromatic hydrocarbons (PAH's) are found to the same
extent in shale oil and crude oil. Hydrotreating can be used to
remove PAH's.
• The storage of incomplete refined or upgraded product may present
a problem in the disposal of solid wastes from the bottoms in the
tank.
• The handling and burning of heavy fuel oils, especially from
coal, may be an issue. This material is likely to be more
aromatic and toxic; probably carcinogenic. Testing is required.
The users anticipate that handling, distribution, and use of heavy
synthetic fuel oils will be an issue. In the utilization of both trans-
portation and boiler fuels, combustion emissions are likely to be the
primary constraint. For low-volume specialty chemicals or by-products
derived from synfuels, the requirements of the Toxic Substances Control
Act, if imposed, would probably keep these products from the market.
A-6
-------
SUPPLIERS
Exxon Company, U.S.A.
Houston, Texas
TOSCO
Los Angeles, California
Shell Oil Company
Houston, Texas
American Petroleum Institute
Washington, D.C.
EXXON COMPANY, USA
September 22, 1980
For Exxon:
T. M. Campbell
R. Campion
T. W. Day
W. W. Hesser
L. Kronenberger
J. P. Racz
R. C. Russell
Technical Coordinator,
Synthetic Fuels Dept.
Environmental Conservation
Coordinator, Public Affairs
Office
Senior Staff Planning Analyst,
Corporate Planning Dept.
Business Development, Synthetic
Fuels Dept.
Regulatory Affairs Coordinator,
Synthetic Fuels Dept.
Project Development Manager,
Synthetic Fuels Dept.
Director, Environmental Health
For TRW:
E. M. .Bonn
J. 0. Cowles
A-7
-------
1. Expected involvement in synfuels industry:
t Exxon is actively and broadly involved in synfuels from shale and
coal. They own a 60% interest in the Colony Oil Shale Project.
Exxon is a major participant in an East Texas coal gasification
project (based on the Lurgi process) for production of
intermediate Btu (IBtu) gas. They are testing a catalytic
gasification process for production of SNG on a small pilot unit
and are actively developing the Exxon Donor Solvent (EDS) direct
coal liquefaction process at their Baytown, Texas R&D center.
• Synfuel products and relative costs estimated by Exxon are shown
in Exhibit 1.
• Shale oil
Probably cost-competitive with crude oil now.
Raw shale oil is equivalent to low-grade crude. It is
aromatic, and contains arsenic, sulfur, nitrogen but has
relatively little residual.
Through coking and hydrogenation processes, raw shale oil
can be converted to a premium crude (low in sulfur and
nitrogen with no residual). For example, in the Colony
project, raw shale oil will be coked, the arsenic removed
and the distillates run through a hydrotreating process.
This will result in a prime feed for refineries--it should
command a higher price than sweet crude.
Will use existing refinery capacity. May need to modify
some refineries for upgrading shale oil. Note that refinery
processes are always in evolution just to handle different
crudes. So shale oil is just an extension of current
technology and practice. Refineries have been continuously
developing capability for handling heavier, dirtier crudes
as the world's sweet crude supply runs out. Shale crude is
right on the trend line for petroleum feedstocks towards
heavier crudes.
Shale oil will produce essentially the same products as
currently produced from petroleum (in the sense of ASTM fuel
specs).
• Intermediate Btu Gas
Technology based on Lurgi is probably cost-competitive now
with imported gas but not with lower price regulated gas.
Exxon favors Lurgi process.
A-8
-------
EXHIBIT I. TYPES OF SYNFUELS AND RELATIVE COSTS
vo
Synfucl
Shale Oil
Process
Heating
KOf
Products
Most Similar To
Cost
Base
Intermediate
Btu Gas
(IBG)
Synthetic
Natural Gas
(SNG)
Methanol
From Coal
Other Liquids
From Coal
Oil Shale
Gasification
Of Coal
Gasification
Of Coal And
Methanation
Gasification
And Synthesis
Indirect And
Direct Routes
Crude Oil
Gas, Largely CO And
H2 For Industrial
Fuels Or Chemical
Feedstock
Gas, Largely Methane
For Distribution
With Natural Gas
Fuel Grade Methanol
And SNG (50/50)
Gasoline, Distillates,
Heavy Fuel Oil And
Up To 50% SNG
Base
15 to 25%
Higher
20 to 30%
Higher
40 to 60%
Higher
-------
Used for industrial fuel gas or chemical feedstock—ideal
for methanol production.
• Indirect Coal Liquefaction
Gives products which look like petroleum-based products.
Fischer-Tropsch gives such a broad range of products—can
get 75 percent gasoline.
t Direct Coal Liquefaction
High fraction of heavy fuel oil products. R&D aims at
upgrading to naphtha and middle distillates, minimizing
residual.
The products from EDS for example, are highly aromatic. The
heavy portions must be upgraded by hydrogenating or
hydrocraking to produce petroleum-like products. The
naphtha will process easily to a prime mogas base stock.
Products will be more aromatic than petroleum products.
While aromatic gasoline is fine, middle distillate products
(e.g., jet fuel) may not be acceptable by today's standards
without excessive hydrotreating.
2. Synfuel products market:
• Shale oil will produce a premium refinery feedstock.
• Intermediate Btu gas plants will most likely serve two end uses;
produce industrial fuel gas and chemical feedstock from a single
plant. Ideal for methanol production.
• Methanol major questions are whether or not methanol will
emerge as a fuel for both transportation and stationary uses.
There is no marketing infrastructure to serve methanol
distribution and end-use market. Technically, methanol is a
viable fuel. There is not much potential as a blend with
gasoline. Can go directly to gasoline from methanol, but this
begins to look like indirect liquefaction. Could be used
initially in a regional system (fleets, counties, military
facility) or as a prime liquid industrial or utility peaking
fuel.
• Coal liquids
Coal liquefaction produces a high fraction of heavy oils.
Actually, probably don't want to make heavy fuels from coal.
The traditional market for these fuels would be utilities/
industrial boilers and these are predicted to convert to
coal combustion and IBtu gas. Some heavy fuel oil may be
A-10
-------
produced in coal conversion plants. This material will be
more biologically active than similar boiling range
petroleum fractions. It will be used as a single
product—not blended.
From EDS, for example, expect to produce fuel for stationary
turbines, special diesel (marine) fuel and home heating oil.
Actually, for home heating oil, won't meet the API spec on
gravity and this will have to be changed or the fuel
extensively hydroproduced. Only minor retrofits may be
required for home heating applications.
For the EDS process, Exxon is working to minimize the heavy
fuel fraction in favor of transportation fuels. Could get
all Naphtha and distillates (up to boiling point of
900 -950 F). Options are many but only at the lab stage
now.
SASOL for example is predicated on the fact that South
Africa must rely on its coal resource base and use existing
gasoline powered equipment. Their economy is too small to
generate new equipment for methanol for example. These
considerations determine the product slate that SASOL
produces.
Projections of demand for synfuel products are given in latest
corporate planning summary, "Exxon Company, U.S.A.'s Energy
Outlook 1980-2000". Note for the first time, Exxon is looking
beyond 1990.
On projections of supplies, Exxon generally gives a lower
picture than DOE.
While 1980 is a unique year since there appears to be no high
peak in summer gasoline demand it is difficult to assess if this
is a permanent trend or a temporary response to rising prices.
We are in the midst of a cycle now.
See Exhibit 2 Exxon predicts a decline in gasoline demand
to the year 2000. Gasoline and fuel oil are shown as
declining faster than the overall petroleum demand. This is
due to increased efficiency, conservation in automobile
uses, substitution of diesel engines for gasoline engines,
and no new oil-fired utility capacity. Distillate products
(home heating oil, diesel, jet fuel) and "other" products
(petrochemical feedstocks) show a growing demand.
Petroleum will continue to be used for products where its
uniqueness brings highest value i.e., transportation fuels
including gasoline.
A-ll
-------
EXHIBIT II. UNITED STATES PETROLEUM DEMAND BY PRODUCT
Growth Rates, %/Year
Million
BPD
20r
15
i
i—•
ro
10
0
Mogas
Dist.
HFO
Other
Total
J
i
1
34
1
Other
i
1
1
Distillate Products
Million
BPD
37
15
10
0
1960 1965 1970 1975 1980 1985 1990 1995 2000
-------
Synfuels will impact the market most readily in the growing
market areas, the middle-of-the-barrel products.
3. Significant factors impacting demand for synfuels:
• Costs see Exhibit 1.
•* Synfuels are expected to account for difference between projected
demand for petroleum products and projected supplies. Domestic
oil supplies are projected to decrease from about 10 MMBPD in
1980 to about 6 MMBPD in 2000. Imports of about 8 MMBPD are
expected to remain, at best, constant to 2000. Overall demand
for petroleum will be about 16 MMBPD in 2000 with oil shale and
coal liquids supplying from 2 to 4 MMBPD. The gas supply/demand
analysis shows gas demand dropping from 10 MMBPD to about 8 MMBPD
in 2000. Domestic production decreases from 8 MMBPD and
synthetic gas accounts for 0.5 to 1.5 MMBPD by 2000.
• Significant government action impacting synfuels:
incentives
shale land leasing
import policy
4. Anticipated period of time to build-up, establish commercial synfuels
industry:
§* Synthetic gas from coal is projected to be commercially available
beginning in the mid-80's. Total annual synthetic gas production
could range to 0.5 MMBPD by 1990. By 2000, synthetic gas
production could range between 0.5 to 2 MMBPD or up to 18% of
total supply.
•* Shale oil and coal liquids will become commercially available
beginning in the mid-80's (shale oil will appear earliest, coal
liquids later in the 80's). Production will range between 0.7
and 1 MMBPD by 1990. In 2000, synthetics could comprise about 20
to 30% of U.S. oil supply or 2 to 4 MMBPD.
• The target on EDS is to have enough R&D information by 1983 to
design a commerical plant.
From "Exxon Company, U.S.A.'s Energy Outlook 1980-2000" Dec., 1979
A-13
-------
5. Synfuel products compared to petroleum based products:
• Shale oil feedstock to refinery, after hydrotreating, will be
considered as a premium feedstock. Products refined from oil
shale will not be different from products produced from crude.
• Coal liquids currently doing tests on EDS product. Each R&D
sponsor receives some of the product and tests are underway for
end use and combustion tests and for toxicology. Information
should become available in 1981.
6. Anticipated modifications to facilities or procedures for marketing
synfuel products.
• No modifications are anticipated other than additional hydro-
processing facilities as for example in use of shale oil and lack
of marketing infrastructure for a new product like methanol.
• May need separate system for heavy aromatic products but we have
experience with this today.
7. Awareness of environmental issues relating to marketing of synfuel
products:
• Handling and burning of heavy oils may be an issues. This
material is likely to be more aromatic and will contain PNA's.
Will have to do some testing here. Have handled similar
petroleum products and know how. But burning is another story
don't know long-term health effects, if any, of combustion
products.
• In the case of shale oil, there is very little residual. It is
processed to clean products and looks like conventional petroleum
products.
• For middle distillates (400-650°F cut), knocking nitrogen out of
the rings is important. Product may be more aromatic but the
customer is used to handling these products. Any contaminants
can be removed. Below 400 F cut (gasoline and lighter) ng PNA's;
below 500 F cut only naphthalene; 4, 5, 6 rings above 700 F.
• PNA's unleaded gasline, for example, has higher content of
PNA's. High, severe reforming adds rings (and hence PNA's) to
product. Catalytic converter in car removes them. Removal can
be accomplished by additional processing should this be
necessary. PNA's in gasoline and synthetics should not be a
problem. PNA's that may also result from inefficient burning
(e.g., for fuel oil applications) will be removed by conventional
emission control devices.
A-14
-------
• Methanol has an effect on the optic nerve, otherwise more benign
than gasoline, for example. Some studies have shown that
methanol spills in water are less of a problem than petroleum.
If gasoline gets into lungs--it is an acute problem.
• Foreign (to U.S.) experience on environmental issues will have no
real impact on Exxon's programs. Do expect to learn from the
SASOL experience.
• As far as meeting current product specifications, don't really
anticipate any problems.
8. Suggestions for EPA approach to controlling utilization of synfuel
products:
• No need for new controls for synfuels. See synfuels as evolution
of conventional products and regulations on existing products
should apply.
• Concerned that regulation issue may impede development of
synfuels industry.
TOSCO
Telephone Interview September 16, 1980
For TOSCO:
For TRW:
G. Ogden
M. Coomes
E. M. Bohn
Manager, Supply and
Distribution Department
Manager, Environmental Health
Effects
1. Expected involvement in synfuels industry:
• TOSCO is involved in the synfuel industry primarily as a supplier
of shale oil feedstock to refiners.
• TOSCO has a 40% interest in the Colony project; Exxon owns a 60%
interest. The TOSCO-II surface retorting process will be used.
The product will be a severely hydrotreated shale oil directly
suitable for the refinery feedstock market. TOSCO is also
involved in the Sand Wash project in Utah but this project is
only in the study stage.
A-15
-------
2. Synfuel products market:
• TOSCO's marketing strategy is to enter the market early in the
Rocky Mountain region. There is at this time, some spare
refinery capacity in this region. In addition, although this
region produces petroleum crude for export to other parts of the
country, the region is a net importer of refined transportation
fuels. Refiners in this region will regard shale oil as a
premium feedstock because of the higher yield of middle
distillate, and transportation fuel products obtained from
refined shale oil.
• Once the Rocky Mountain area market is satisfied, the next or
longer-term market is expected to be in the upper Midwest.
Currently, there is about 200,000 BPD open pipeline capacity to
refineries in St. Louis, Chicago and Detroit. This is expected
to increase to 300,000 BPD open capacity by 1985. The export
(from the Rocky Mountain area) market is expected to develop in
the Midwest.
3. Significant factors impacting demand for synfuels:
• Availability of petroleum crude oil, especially as it may be
impacted by production from the Overthrust Belt in the western
states will impact the market for shale oil. Overthrust
production could absorb all in-place pipeline capacity.
t As long as the U.S. imports oil, there will be a demand for
domestic hydrocarbon that will provide some incentive to look at
synfuels. National security will always be a consideration.
• Government incentives are absolutely necessary to accelerate the
early development of commercial scale plants. The industry is
not capable of providing the capital for such a large investment.
4. Anticipated period of time to build-up, establish commercial synfuels
industry:
• Highly speculative but TOSCO agrees that the Government's target
of 500,000 BPD from oil shale by 1992 is reasonable. In-house
estimates place national production level at 300,000 BPD by 1990.
5. Synfuel products compared to petroleum-based products:
• Crude petroleum has a range of compositions that bracket crude
shale oil. One exception is the nitrogen content of oil shale.
Hydrotreating will remove N compounds (along with sulfur). The
arsenic present in oil shale would poison refinery catalysts.
The arsenic is removed in a guard bed made up of spent or
deact i vated cata1yst.
A-16
-------
There are no compositions unique to oil shale as compared to
petroleum.
• As far as end use products are concerned, they will be produced
according to specifications; gasoline is gasoline as defined by
specifications. One must understand the refinery process and the
impact of differences in crude oil feedstocks to appreciate the
production of an end-use product. For example, gasoline is
produced by blending several process streams to meet a certain
set of specifications (aromaticity, viscosity, volati1ity,etc.).
Note—it is not the final product itself that is defined under
TSCA for example. It is the chemical substances of the product
streams that are listed.
6. Anticipated modifications to facilities or procedures for marketing
synfuels products:
• Oil shale can be distributed in any of several ways. It is more
economical to hydrotreat the crude shale oil and then distribute
by pipeline.
• The handling, distribution, and storage of shale oil will be the
same as for conventional petroleum feedstock.
7. Awareness of environmental issues relating to marketing of synfuel
products:
• In general, no new controls or regulations will be required for
oil shale. The only difference from a marketing standpoint
regarding use of shale oil is that there will be an increase in
utilization of hydrocarbon products in the Rocky Mountain area.
• Regarding potential carcinogenicity of shale oil, it looks like
it will be bracketed by petroleum crudes. Note—only two
different crudes have been tested to date.
TOSCO is actively involved in toxicity tests on oil shale. (Two
reports will be sent to TRW.) Tests on shale oil from the retort
indicate that it has the same carcinogenicity as some
conventional industrial fuels currently in use. (The
characteristics of the fuel oil depends on processing and
feedstock used.) As far as polycyclic aromatic hydrocarbons
(PCAH's) are concerned, no difference between shale oil and crude
oil has been found. Hydrotreating reduces PCAH's in shale oil.
Carcinogenicity is really an emotional issue. TOSCO finds that
shale oil has the same or lesser potential for impact than
conventional crude.
A-17
-------
8. Suggestions for EPA approach to controlling utilization of synfuel
products:
• Compare hydrotreated oil shale to petroleum crude.
• No special controls needed.
SHELL OIL COMPANY
September 22, 1980
For Shell: K. Geoca External Activities
C. Jones Manager, Business Center
for Synfuels
For TRW: E. M. Bohn
J. 0. Cowles
1. Expected involvement in synfuels industry:
• Shell Oil Company has not really been involved actively in
synfuels until now. Have had some peripheral R&D activity and
have an interest in:
Tar sands in Canada
Oil Shale -- Modest interest
Coal as a general resource
Shell has a significant position in coal resources in the U.S.
and this has led to synfuels interest.
t Shell is now acquiring coal gasification technology from Shell-
Koppers and expects to be on leading edge of second generation
technology.
Studies now underway by EPRI should show Shel1-Koppers technology
more efficient than Texaco.
2. Synfuel product market:
0 Will produce medium Btu gas from Shell-Koppers process.
• Market, in order of penetration will probably be:
A-18
-------
Power Plant fuel
Industrial boilers
Feedstock for chemicals, methanol
Feedstock for liquefaction of coal
Coal liquefaction (Mobil-M)
3. Significant factors impacting demand for synfuels:
• SFC formation Energy Security Act
• Windfall profits tax and impact on investment in synfuels
• Price of crude oil
4. Anticiapted period of time to build-up, establish a commercial
synfuels industry:
• Shell-Koppers pilot plant in Amsterdam now. By 1984, 1000 T/day
demonstration plant planned.
5. Synfuel products compared to petroleum-based products:
t No difference for Shell-Koppers process considered here
6. Anticipated modifications to facilities or procedures for marketing
synfuel products.
Not applicable
7. Awareness of enviornmental issues relating to marketing of synfuel
products:
t Expect to comply with regulations as they are now known.
8. Suggestions for EPA approach to controlling utilization of synfuel
None
A-19
-------
AMERICAN PETROLEUM INSTITUTE (API)
September 5, 1980
For API: B. R. Hall Synthetic Fuels Director
B. L. Petersen Senior Analyst for Synthetic
Fuel s
D. B. Disbennett Health Affairs Coordinator
E. Rucker Environmental Affairs Assistant
Director
P. J. Fuller Regulatory Analyst
For TRW: E. M. Bohn
R. S. Iyer
1. Expected involvement in synfuels industry:
• The oil industry is interested in those technologies that are
most directly transferable to the current manufacturing and
distribution system. Oil is a finite resource and they feel that
they need to be involved in a broad array of potential
opportunities (e.g., SRC's, EDS, etc.), constantly assessing the
economics and technology.
• As far as timing for synfuel industry build-up, some at API feel
that TRW's nominal scenario looks very reasonable. They feel
oil shale will come along earliest the technology is further
along and the economics look better than the rest now. Major
unknown is the development costs as they are impacted by
environmental legislation not yet promulgated. Probably won't
get to 500,000 BPD by 1987 permits will hold up development.
t Synfuel plants will be located near the resource. Refineries
will be located as they have been traditionally near supply or
near population density. The selection of a certain technology
(e.g., gasifier type) is highly site specific. Note second
generation gasifiers such as TEXACO and CONOCO are being selected
now.
2. Synfuel products market:
• In the case of oil shale, syncrude will be sent to a refinery and
a complete slate of products will be produced. The military
market is forced into securing transportation fuels, especially
jet fuel from oil shale. At this moment, there is a big need for
testing of synfuel products—this will be largest demand for
products over first few years.
A-20
-------
• The consumer will know no difference between traditional
petroleum fuels and synfuels. There is no identifiable "demand"
for synfuels. All toxic components will be removed before
consumer sees products. All products will meet current specs.
Such things as aromatics, carbon, trace elements, will be
control led.
3. Significant factors impacting demand for synfuels:
• A synfuel industry has to be developed even though it may
strain our resources. As far as captial goes we can do it if the
need is there. In the sense of a national effort or emergency,
we can do whatever we want.
t Conservation has impacted the demand for fuels. This is a direct
result of price increases and the current economic recession.
The long-term trend, even with conservation will be one showing
an increase of 1 percent per year, somewhat below traditional
trend. The fact is, we are dealing with a finite resource and an
increasing world demand, especially in the third world countries.
• Government incentives and regulations will be a big factor. OPEC
price control can be overcome by price guarantees. Beyond the
Synthetic Fuels Corporation, one can't predict what will happen.
Synfuels will be treated as any other business investment oppor-
tunity. It is a matter of short- vs. long-term and synfuels are
definitely a long-term opportunity. Most of the large oil com-
panies will be synfuel producers when it happens, they intend
to be there.
• Government regulations produce another series of unknowns in the
investment decision. They raise the margin for success.
Government is not consistent. On the EMB, we don't need a new
agency rather, revise existing legislation and regulations.
4. Anticiapted time to build-up, establish commercial synfuels industry:
• The TRW nominal scenario looks very reasonable; API agrees with
it. As far as build-up flattening out after initial plants are
built, API feels most development data will be obtained over next
5-10 years and the industry may have no need to pause. The
build-up depends very directly on government participation and
the availability of foreign crude oil at a competitive price.
t Environmentally, the Clean Air Act is key—water is next. How
these areas are going to trend as far as business encouragement
goes over the next few years is a key issue. TSCA may also be
key depending on what the implementing regulations say.
5. Synfuel products compared to petroleum-based products.
A-21
-------
t As far as physical and chemical characteristics of synfuel
products are concerned, they will be esstentially no different
than the refined petroleum-based products. After refining and
upgrading, all products will meet product specifications.
• All petroleum crudes are different and the processing is tailored
for each crude. Product specifications are satisfied by various
degrees of hydrotreating. This additonal processing or upgrading
is a matter of economics. The trend in the U.S. is to upgrade
the bottom of the barrel. The need for additional hydrogen is
the same problem posed for synfuel upgrading. Processing and
refining of synfuels will be very analogous to conventional
petroleum processing problems.
Note the characterization of petroleum has been going for years
and it will continue. The processes will continue to be improved
as a more complete basic understanding of the nature of petroleum
is obtained.
• Technically, the industry can meet product specifications for
synfuel-based products. The market place will handle this aspect
well the buyer will specify and the supplier will meet the
specs. Price of products will depend on specifications. One
concern may be the impact EPA may have on new specifications.
6. Anticipated modifications to facilities or procedures for marketing
synfuel products:
• As far as synfuel products are concerned, through the year 2000,
there will be no change in end use or utilization devices and
equipment one must accept this fact. Products will be produced
for this equipment according to ASTM specifications. One
possible exception is the nitrogen content which is under study
now. Another exception may be methanol production. Some
equipment modification would be needed for methanol. We might
see fleet cars running on 100% methanol in the 1990's.
• As far as handling and distributing synfuel products, there will
be no risk for end-products since these will meet current
specifications. All potential contaminants and toxic material
can be removed in processing.
• Transporting syncrude may be a problem. The syncrude will be
hydrotreated to the point that is meets specs for pipelining
(corrosion, pumping, pour point specs). It is a matter of
economics and the entire system must be considered.
• In the case of some products that may not be refined (e.g.,
boiler fuels), they are being characterized now. Problems will
be identified and handled. The products will meet specs.
A-22
-------
7. Awareness of environmental issues relating to marketing of synfuel
products:
• For end use products after refining and upgrading products
specifications will be met. Environmental risks will be the same
as for current products. The assumption (in the draft report)
that toxic feedstock going in means toxic product coming out is
wrong.
Economics considered, processing will be tailored to meet product
specs. One cannot assume that there is significant difference
between regular and synfuel-based end products.
• Important environmental issues:
Work place (synfuel plant) exposure is most important.
The storage of incomplete refined or upgraded product may
present a probelm in the disposal of solid waste from the
bottoms in the tank. The industry is dealing with problem
the regulations have just come out.
Spills are expected to pose no additional problems for
synfuels; API plans to work on problems associated with
synfuel spills.
• See Exhibit 3 Toxicological Assessment of Retorted Shale Oil
Refinery Products and Streams a summary of tests being
sponsored by DOE, DOD and API.
8. Suggestions for EPA approach to controlling utilization of synfuel
products:
• When considering toxicity compare synfuels to petroleum
products. Talk about relative impacts, not absolute. Do tests
on both petroleum and synfuels.
t TSCA could be a real stopper for industry. Is there any reason
to consider TSCA for synfuel products that meet specs? API
intends to make recommendations to EPA on need for Premanufacture
Notices. An undue burden is placed on industry by requiring all
test data during the industry development. Testing should be
done concurrently with development.
• Regulations must make common sense. They must not impede
development.
A-23
-------
ro
EXHIBIT III. CONJOINT TOXICOLOGICAL ASSESSMENT OF RETORTED SHALE OIL REFINERY
PRODUCTS AND STREAMS
^VToata
Shalo Oil ^"^N^
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Rutort Oil
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JP-5 (|>ra-acld treat)
JP-8 (prc-ncld Croat)
DFM (prc-arld Croat)
JP-4 (final)
JP-5 (flnnl)
JP-8 (final)
DFM (final)
Acid Sludge
Retort Oil
Wntor (Separation)
Water (From stripper)
[Acute ||
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noK
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-------
USERS
General Motors
Warren, Michigan
A Major Chemical Company
Department of the Navy
Washington, D.C.
Electric Power Research Institute
Palo Alto, California
GENERAL MOTORS
October 1, 1980
For GM: J. M. Colucci Department Head, Fuels
Lubricants Department
For TRW: E. M. Bonn
J. 0. Cowles
K. Lewis
1. Synfuel products market:
t The aim of GM's research organization, including the Fuels and
Lubricants Department, is to assure that GM products will operate
on available fuels, now and in the future. In 1971, GM began
looking at non-traditional fuels as potential supplement or
replacement for petroleum-derived fuels. Alcohols were first.
Their primary interest is future hydrocarbons. Some tests on oil
shale distillates (for gas turbines) have been done. GM expects
to receive samples from Gulf, Ashland, and Exxon for coal liquids
testing early next year.
• Among the auto industry, GM has the lead in application and
testing of synfuels. Other than some work by Ford on alcohol
fuels, there is very little else outside of GM going on in this
arena.
t GM has a very good line of communication with the oil companies/
suppliers of synfuels. A group, the Coordinating Research
Council, made up of representatives from the oil, auto and
equipment manufacturing companies, has also been active with work
on alternative fuels. The CRC is headed by A. Zengel and is
headquartered in Atlanta.
A-25
-------
• Projection of synfuel market:
Oil shale is competitive now with imported oil.
Demand for diesel fuel will increase; gasoline demand will
decrease. GM projects that 20 percent of its fleet will be
dieselpowered by 1985 compared to 5-7 percent now.
2. Significant factors that will impact supply of synfuels:
t Great dependence on OPEC.
• Among the synfuels that will be produced, diesel fuel will be
competing with other middle distillates such as jet fuel as the
demand for diesel fuel increases.
3. Synfuel products compared to petroleum-based products:
• For the most part, the user will not identify any differences
between petroleum products and synfuels. For example, the SUN
Oil Toledo refinery has produced some gasoline derived from tar
sand feedstock. It is used just as regular gasoline is used no
one knows the difference.
4. Anticipated modifications to facilities or procedures for utilization
of synfuel products:
• In general, suppliers can process synfuel feedstocks to yield any
specified product. The amount of processing is mostly a matter
of economics. This is DOE's feeling fuels can be made to
specs. But GM feels that processors and users should meet
part-way for optimum utilization of synfuels. If a producer is
only making a product to certain specifications, some of the
advantageous properties of synthetics may be neglected. For
example, for the high content of aromatics present in coal
liquids, one may want to develop a higher compression engine for
more efficient operation.
t The balance between additional processing of synfuels versus
engine modification is a matter that is being investigated by
experimentation. As a first step, GM will look at a less refined
or processed synfuel product. A series of tests will be
scheduled beginning with fuel characterization e.g.,
aromaticity, sulfur, volatility, octane quality, etc. Next,
tests of performance will be made in a single cylinder engine.
After these initial tests, GM will begin to iterate with the
supplier on fuel specifications e.g., a tighter spec on sulfur
may be requested. At the same time, GM begins to look into
possible engine modifications to utilize fuel effectively.
Eventually, full scale multi-cylinder tests are conducted and
actual auto engines are tested. Longer range testing is required
A-26
-------
for such things as materials compatibility. It is this whole
system approach to development of synfuel products that is
requi red.
• GM is willing to look at less refined, cheaper fuels but
ultimately EPA standards will determine whether or not a product
can be used. For example, consider the fuel-bound nitrogen in
shale oil. Although engine performance may not be affected by a
nitrogen level yielding emissions of 1.2 grams/mi., it may turn
out to be too costly to process the fuel to meet a standard of
1.0 gram/mi.
• Although we do not know the ultimate effect on costs of refining
and/or engine modifications, refining and processing will
probably be the primary path to acceptable use of synfuels. For
example, in the case of diesel particulates, although GM has done
much work in this area, better or improved processing is needed.
More definitive health effects data would help.
5. Awareness of environmental issues relating to utilization of synfuel
products.
• GM believes synfuels use constraints are economics, emissions,
and safety but that economics as affected by regulation on
emissions and safety of synfuel production and use is the primary
constraint. Specifically, EPA and other Federal regulations will
be the prime driver in the gasoline/automotive synfuel system.
t Issues will be generally the same as for conventional fuel use.
Some points:
Arsenic in shale if it carries over to product used in
cars, it will poison the catalytic converter catalyst.
Would have disposal problems.
Since 1974 EPA has regulated additives to unleaded gasoline.
Synthetics will probably be impacted by this regulation.
Note that we can make highly aromatic fuels with no PNA's
but the combustion of this fuel will yield PNA's in the
microgram/mi range. Catalytic converters can remove PNA's
but how much can be tolerated? PNA's will be an issue and
the burden will fall, at least in part, on the auto
manufacturer.
Note that the issue of ethyl alcohol as an additive to
unleaded gasoline was waived as a result of benign neglect.
But evaporative emissions are high (10-25% vapor pressure
increase) and should be addressed.
A-27
-------
A MAJOR CHEMICAL COMPANY
September 17, 1980
For Chemical Company:
For TRW:
Manager of Petrochemicals
J. Cotter
J. Cowles
1. Synfuels Products Market:
• Identification of major synfuel product suppliers:
The most probable synthetic feedstock used in the chemical
industry will be medium-Btu gas;* they do not know whether they
would make their own gas or buy it. They would not use SNG under
any circumstances. Naphtha and gas oil from shale oil refining
should be good cracking feeds. Later (in the 90's), LPG from
coal liquefaction, together with coal-derived naphtha and BTX
will become available for chemical feedstocks. They do not
understand why anyone would build a Fischer-Tropsch plant.
• Projected demand for synfuel products:
The growth rate of synfuels as chemical feedstocks won't be all
that high. They think less than 50 percent of chemical
feedstocks will be synthetic by 2000, since the industry can't
convert any faster. In addition, the recent 6-10 percent growth
rate of the chemical industry is almost sure to slow down to 3-4
percent by 1990, as natural products become more competitive with
manufactured chemicals and products.
2. Significant factors that will impact conversion to synfuels as
feedstock:
• The availability of existing feedstocks is a key issue.
Tennessee Eastmen probably does not have any good options to
their current coal-to-syngas effort. Both natural gas and resids
{for gasification) could be interruptible feedstocks for them.
They (Chemical Company) are in much better shape on feedstock
contracts.
t The competitive prices for synthetic LPG, naphtha, etc., are not
yet determined, but both price and forecasted availability will
determine the switch to other feedstocks.
*The advantages for oxygenated chemicals look really good,
A-28
-------
Synfuel products compared to petroleum-based products:
• Synthetic LPG will be just like it come out of the ground. Acid
gas purification of medium Btu gas will take out all the trace
contaminants, so that is will look like regular syngas.
• Coal liquefaction products, like naphthas, may be different, and
may contain PNA's and substituted phenols.
Anticipated modifications to facilities as procedures for utilization
of synfuel products:
• They are already working on plant concepts (in R&D) that would
use synthetic feedstocks. Their first synfuel-tailored process
will be ready in the late 80's.
• Synthetic methanol, as a fuel, could be used right now, if
necessary.
Awareness of environmental issues relating to synfuel utilization as a
feedstock:
• Although some synfuels may have PNA's, etc., they face this
situation right now with resids from heavy liquid pyrolysis.
These products are now sold on the open market as a No. 6 fuel
oil blend, since they have low sulfur content. They do not think
any extra environmental controls are needed. Good practice right
now dictates that these materials must be well contained, since
they have to be handled hot.
t They are under the impression that neither synfuels nor their
derived by-products would be subject to TSCA. If they did have
to requalify any derived by-products, low-volume specialty
chemicals might be discarded from market consideration.
• They feel that the extensive conversion which is characteristic
of chemical operations (as compared to refining) would also
convert hazardous constituents found in the feedstocks.
They do not see any justification for EPA to regulate synfuel
utilization.
DEPARTMENT OF NAVY
September 5, 1980
For the Navy: Dr. A. Roberts
A-29
-------
For TRW: E. M. Bohn
R. S. Iyer
K. R. Lewis
1. Synfuel products market:
t The Defense Production Act provides for 3 billion dollars in
purchase guarantees for synfuels. These incentives, along with
those of the SFC, are expected to stimulate the development of a
commercial synfuels industry and to assure fuel supplies for DOD.
DOD buys on the open market through a central military
procurement office. All purchases are made according to military
specification (mil-specs). It is expected that synfuels will be
procured in the same manner with suppliers identified as the
traditional fuel suppliers.
2. Significant factors that will impact supply of synfuels:
0 Government incentives, especially price guarantees.
• Availability is a national security issue. Longer term depletion
also is a problem. Equipment (ships, planes) being designed now
to operate on conventional engine technology. The need is for
traditional hydrocarbon fuels. Alcohol, methane, etc. cannot be
used here.
3. Synfuel products compared to petroleum based products:
• The characteristics of synfuels are being studied now and some
differences have been identified (e.g., high nitrogen content in
shale-derived fuel). At this point, it is not known if
processing or upgrading can be used to meet specifications. Have
only looked at one source and one process (Paraho/SOHIO test).
§ The Navy (as also other branches of DOD) has a very active R&D
program focused on characterizing synfuels for end-users
primarily engines. This program includes laboratory testing to
quantify test fuel chemical and physical properties and to
identify adverse effects upon system performance. Fleet tests
are planned as fuel samples become available. Health, safety and
environmental concerns will also be addressed.
4. Anticipated modifications to facilities or procedures for utilization
of synfuel products:
• For the next 10-20 years, current equipment (planes, ships) will
continue in use. The capital investment in these equipment is
large and the fuel must fit the equipment. Minor modification,
some retrofits are possible.
A-30
-------
0 Note that the buyer's fuel specifications have evolved over the
years around a stable, traditional source of crude. These specs
are not designed to pick-up problems among different crudes and
certainly not for a new product like synfuel. For example, in
the case of Alaskan crude, had to hydrotreat more than other
crudes and this destroyed lubricity of product. This produces a
direct effect on fuel pumps in aircraft engines. Fuels will
continue to be modified. The synthetics will definitely pose a
greater problem. For example, none of the military specs account
for nitrogen, and it is known that nitrogen causes gumming. This
has not been a problem before.
• Toxicity if related to trace elements might be taken care of
(eliminated) by drawing up certain specifications.
• From utilization point of view, the supplier must meet specs
including health hazard specifications. The engine manufacturers
must quality engines for the military spec fuels.
t The Navy is interested in all synthetic fuels. If they meet
specs, will use.
• Oil shale products appear more nearly able to contribute at this
point costs are competitive and the industry is developing
faster than others. The middle distillate yield from oil shale
is good also jet and diesel fuel.
5. Awareness of environmental issues relating to utilization of synfuel
products:
• Haven't discovered any significant issues. Work is under way and
continuing.
• Have not identified any special need for controls or procedures
yet.
6. Suggestions for EPA approach to controlling utilization of synfuel
products:
• Use petroleum as a baseline when evaluating health effects of
synfuels. Should only be concerned over results that show
"worse" than conventional products. Then, look at controls for
these cases.
A-31
-------
ELECTRIC POWER RESEARCH INSTITUTE
September 29, 1980
For EPRI: R. Wol k Director, Advanced Fossil
Power Systems Department
For TRW: J. Cotter
1. Synfuel Products Market:
• Projected demand for synfuel products:
Base load: the big use will be medium-Btu gas, which (with
combined cycle operations) will be competitive with
pulverized coal-fired boilers. The Southern California
Edison plant at Coolwater is going ahead.
Intermediate load: The utilities can't afford big
expeditures for this level; liquid products in combined
cycle are likely.
Peaking: probably gas turbines with methanol or upgraded
liquids.
Petroleum liquids will dry up as a utility fuel as early as
1990, and certainly by 1995. Although We have a temporary
excess of natural gas, that's going to disappear too.
• Identification of major synfuel product suppliers
Oil companies are most likely suppliers of liquids, but
utility consortiums can't be ruled out—the advantage are
substantial for utility financing.
Utilities will probably make their own medium-Btu gas;
traditional utility suppliers like CE, B&W, and Westinghouse
might be potential sources.
Shale oil liquids will be the first on line, although much
of the shale oil product split will be diesel fuels.
Coal liquids must be on line by 1990 to take up the
petroleum short fall.
2. Significant Factors that will impact supply of synfuels:
• Resource availability picture looks to be improving; lignite
yields are looking better (from gasification and liquefaction).
A-32
-------
• Improved gasification and liquefaction technology should yield
more products from coal.
• Costs: $6-7 million Btu is a competitive price, coming from a
$2-3 billion, 60,000-BPD direct liquefaction plant.
Synfuel products compared to petroleum-based products:
• Distilled shale oil products will look most like petroleum
products
0 Coal liquids (without upgrading) will have high sulfur, nitrogen,
and carbon ratios.
• Compatibility is in question.
Anticipated modifications to facilities or procedures for utilization
of synfuel products:
• Shale oil resids can be used in turbines--EPRI demonstrated that
at Long Island Lighting plant test. Water injection moderates
NO emissions.
A
• Utilities will use the lowest grade fuel that will combust and
meet regulations; advanced turbine designs will be needed;
Westinghouse has demonstrated that special combustor designs can
burn liquids down to 10% H content.
• Resid coal liquids must be segregated; won't blend with petroleum
oils.
Awareness of Environmental Issues Relating to Synfuel Utilization
• They recognize that pipelining, barging, and tank car transport
could be a problem; EPRI has just issued a contract to Gulf to
look at potential emissions.
• Don't know real risks of handling these materials at a power
plant.
• They are not excited about SRC 1iquids--think that their S&N
content is higher than they might expect from some other
liquefaction processes.
Liquid fuels will certainly need some form of combustion
modification; they did staged combustion with the SRC II
test at Con Ed.
No. 6 type fuels may require ESP use.
A-33
-------
Distillate products may be favored for lower NOX, ash
generation.
6. Suggestions for EPA approach to controlling utilization of
synfuel products:
EPA should not attempt to duplicate what DOE may do
relative to synfuel utilization regulation.
A-34
-------
APPENDIX B
COMMERCIAL COAL LIQUEFACTION
AND GASIFICATION PROJECTS
B-l
-------
TABLE B-l. COMMERCIAL COAL LIQUEFACTION AND GASIFICATION PROJECTS
PROCESS
Sasol2
Lurgl Sasol1
Lurgl Sasol1
Lurgl Sasol2
Texaco
CO 1
i Texaco
ro
Koppers-
Totzek
Undecided
Mobil M-3
Gasoline
Lurgl1
PROJECT AND CONTRACTOR
Fluor and Crow Indians
East Texas Project,
EXXON Coal USA
South African Coal , 011
and Gas Corp. Ltd.
Texas Eastern &
Texas Gas
Texaco & Houston
Natural Gas
Methanol from Coal ,
Wentworth Bros.
Synthetic Fuel Lique-
faction Plant, W.R.
Grace & Co.
EXXON Wyoming1 Project,
EXXON Coal U.S.A.
Mobil Oil Co. & New
Zealand Liquid Fuels
Trust Board
Panhandle Eastern
Wyoming Project
Panhandle Eastern &
Pea body Coal Co.
MAJOR PRODUCTS
SNG Liquids
Med. Btu Gas &
Liquids
SNG, Liquids
SNG, Liquids
Methanol Fuel
Gas
Methanol
Methanol , Carbon
Dioxide
SNG, Methanol
Gasoline LPG
SNG
COMMERCIAL CAPACITY
65,000 BBL/D
Med. Btu Gas: 400
MMSCFD Liquids:
10,000 BBL/D
__
50,000 BOE Equivalent
2 plants producing
total of: Methanol
25,000 B/D Med. Btu
Gas 300 MMSCFD
7.5 MM gpd = 179,000
BBL/D
Methanol: 5,000 TPD
CO,: 6,000 TPD
c.
_ m
12,500 BBL/D
125 MMCFD Capacity
COST LOCATION
Montana
$2 billion Cherokee &
plus Rush Co.,
Texas
$2.8 billion South
Africa
Henderson,
Kentucky
$500 MM per Convent,
plant Loulslanna
$2.2 billion
« « — —
Glllete,
Wyoming
$500-650MM New Zealand
$1 Billion Douglas,
Wyoming
STATUS
„
Supply Demand
Studies of
Feasibility
Near Completion
Site 1s being
Negotiated
Feasibility
Studies
Planning and
Negotiation
__
Planning
Negotiation
Proposal
COMMERCIAL
START
..
„
1980
— ..
--
..
1984-1985
__
-------
TABLE B-l. (CONTINUED)
• PROCESS
Lurgl1
Lurgl2
Lurgt1
Lurgi1
(Tentative)
Lurgl1
_ Texaco4
CO
i
CO
Undecided
Undecided
PROJECT AND CONTRACTOR MAJOR PRODUCTS COMMERCIAL CAPACITY
Peoples Gas Dunn Co. SNG
Project, Natural Gas
Pipeline Co. of America
Rocky Mountain Energy SNG
Corporation
Great Plains Gasification SNG
Project
Mountain Fuel Supply SNG
Co., SNG Project
Burnham Coal Gasification SNG
Project, El Paso Natural
Gas Co. & Ruhrgas A.G.
Texaco & Transwestern SNG
Pipeline
•i
TENNECOl SNG from Coal SNG
SNG from Coal1 Texaco SNG
Inc. , Transwestern
250 MMSCFD
250 MMSCFD
137.5 MMCF/SD
(expandlble to
250 MMCF/D)
125 MMSCFD expandable
to 250 MMSCFD
Initial: 72 MMSCFD
Expanded: 288
MMSCFD
250 MMSCFSD
--
125 to 250 MMSCFSD
COST LOCATION
$1 Billion Dunn County,
No. Dakota
Southern Wyoming
Cherokee Coal
Reserves
$890 MM Mercer County,
No. Dakota
Emery, Utah
$42 Million New Mexico
for 72 MMSCFD
Plant
Buffalo,
Wyoming
Wlbaux,
Montana
Lake Desmet,
Wyoming
COMMERCIAL
STATUS START
— _ — _
Feasibility Late
Study 1980's
Negotiation
Start-up plan- 1990
ned for 1988
Negotiation
Stage
Feasibility
Study
Acquiring Coal
Reserves Nec-
essary to fuel
plant
Planning
HYGAS0
U-Gas1
Pi pel1ne Company
Montana Power Co., &
Montana-Dakota Utilities
A1r Force
Industrial Fuel Gas Demon-
stration Plant, Memphis
Light, Gas & Water
SNG
Medium Btu Gas
35-100 MMSCFSD
175 MMSCFD
I300-500MM
Shelby County, Detail Design
Tennessee
(continued)
-------
TABLE B-l. (CONTINUED)
PROCESS
Texaco1
Texaco'
Shell -Koppers
Undecided
Undecided
Undecided
HYGAS1
Texaco1
Texaco1
(Tentative)
PROJECT AND CONTRACTOR
CBA5CO Services
Chemicals from Coal
Tennessee Eastman
Company
--
Low/Med, Dtu Gas fop
Multl -Company Steel
Complex
Columbia1 Coat Gasification
DeSota Countyl Mississippi
Coal Project
KEN-TEX Project, Texas
Gas Transmission Corp,
m w
Combined Cycle Coal
Gasification Energy
Centers
MAJpR._PRppUCT5
Synthesis Gas
Synthesis Gas for
Captive Use
. „
Low/Med But Gas
High Btu Gas
SNG
High Btu Gas
Ammonia
SNG, Fuel Gas,
Electrical Power
-' '-I...... . .,. .. - , — ~— ;___—-_-.
COMMEBCJAL CAPACITY. COST LOCATION
Louhf/nirui
Kfngsport,
Tonnessee
1,000 TPI) Coal Food -- Netherlands
Northern
Indiana
Illinois
.. . - .-
ZSO MMSCFD -• Illinois
Basin
1200 TPD $518 MM Baskett,
Kentucky
2 plants each producing: $116 Million Cameron,
SNG! 33 MMSCFD; Fuol Missouri
Gas! 42 MMSCFD; Power
300 MW
STATUS
Preliminary
engineering
Design
w-
Demonstrate
Plant Under
Design
Planning
Planning
Feaslbllty
Study
Planning
Detailed
Design
Construction
scheduled
for mid- 1981
COMMERCIAL
START
* •
1963
ri
..
** •
..
..
Results of Demo
Plant Testing
could have major
Impact on commer
dal start
1964
(continued)
-------
TABLE B-l. (CONTINUED)
PRQCXSS
9
Texaco
Texaco7
PROJECT AND CONTRACTOR
Central Maine Power
Company
Texaco A Southern
California Edison
MAJOR PRODUCTS
Electric Power
Electric Power
COMMERCIAL CAPACITY COST
-18,000 KW
90 MW 1000 TPD $300 MW
Coal
LOCATION
n •
Gar stow
California
STATUS
Planning
Preliminary
Design
COMMERCIAL
START
1987
1983
00
en
1, Caroerpa Synthetic Fuels Report, The Pace Company Consultants and Engineers, March 19QQ.
2, Synfuels, McGraw-Hill, May 0, 1900,
3, D, J, Deutseh, A B1o Boost for Gasoline from Metnanol. Chemical Engineering, pp. 13-15, 1/7/80,
4, SynfueU, November 9, 1975,
5, Synfuels, April 1, 1980,
6, Synfuels, December 7, 1979,
7, Synfuels, January 1, 1980,
-------
APPENDIX C
COOPERATIVE AGREEMENTS AND
FEASIBILITY STUDY GRANTS FOR SYNFUELS
C-l
-------
COOPERATIVE AGREEMENTS
TECHNOLOGY
REQUESTED FROM DOE
DESCRIPTION/SITE
Coal Liquids
Texas Eastern Synfuels
$24,300,000
o
i
ro
High-Btu Gas
Great Plains
Gasification
Associates
$22,000,000
Texas Eastern Synfuels proposes to construct a coal
liquefaction facility that will produce the equi-
valent of 56,000 barrels of oil per day. Texas
Eastern Synfuels is a joint venture of Texas Eastern
Corporation and Texas Gas Transmission Corporation.
The proposed project is a Fischer Tropsch plant--
like the SASOL facility in South Africa—that would
convert approximately 28,000 tons per day of coal
into a mixture of transportation fuels, synthetic
natural gas (SNG), and chemicals. Approximately
44 percent of the output is SNG {145 mmSCF/D); about
30 percent is transportation fuel. The test chemicals
site is near Hendersen, Kentucky.
The project will use a Lurgi pressurized, fixed-
bed gasification process with Lurgi methanization re-
quiring 14,000 tons/day of lignite coal to produce
137.5 mmCF/day of synthetic gas, 93 tons/day of
ammonia and 85 tons/day of sulfur. The facility will
be sited in the Beulah Hazen area of Mercer County,
North Dakota and has a total capital requirement of
$1.5 billion.
Wycoal Gas
$13,155,000
Wycoal plans to construct a facility using Lurgi and
Texaco gasification units to process 16,000 tons of
sub-bituminous coal daily to produce high-Btu gas.
All liquid by-products will also be gasified. The
facility is to be located in Douglas, Uyoming. The
proposed work will involve developing a definitive
basis for plant design,estimating costs, securing
permits and approvals, obtaining financing, and
identifying long-lead delivery items. There is a
market for the SNG via pipeline system, owned by
the participants, to the midwest. The project
would produce the equivalent of 51,000 barrels of
oil per day.
-------
FEASIBILITY STUDY GRANTS
TECHNOLOGY
REQUESTED FROM DOE
DESCRIPTION/SITE
o
i
GO
Coal Liquids
Cook Inlet Region
Anchorage, Alaska 99509
W. R. Grace
Denver, Colorado 80223
Clark Oil & Refining
Milwaukee, Wisconsin 53227
$3,900,000
$ 786,477
$4,000,000
Houston Natural Gas/Texaco
Houston, Texas 77001
AMAX, Inc.
Grenwich, Connecticut
Dakota Company
Bismark, North Dakota
58501
$3,260,000
$2,190,000
$4,000,000
Feasibility study of producing 54,000 barrels per
day of methanol from low sulfur coal using Winkler
gasifier and ICI methanol synthesis.
Site: West side of Cook Inlet, Alaska
Stage III of a feasibility study of a coal sourced
methanol plant using a Koppers-Totzek gasifier.
Site: Moffat County, NW Colorado
Feasibility study of producing synthesis gas from
coal, steam, oxygen, and methanol from synthesis
gas using a Koppers-Totzek gasifier, ICI, and the
Mobil-M process.
Site: South Illinois
Fourteen-month feasibility study of producing fuel
grade methanol from coal using Ziegler coal deposits.
Site: Covent, Louisiana
Feasibility study of a coal-to-methanol plant pro-
ducing 14,910 barrels per day using Koppers or Lurgi
gasifiers.
Site: Duluth, Minnesota
Feasibility study for constructing an 85,000-barrel/
day coal-to-methanol plant using Lurgi gasifier and
Lurgi methanol synthesis.
Site: Dunn, North Dakota
(continued)
-------
FEASIBILITY STUDY GRANTS (CONTINUED)
TECHNOLOGY
REQUESTED FROM DOE
DESCRIPTION/SITE
o
Republic of Texas Coal $ 808,781
Co. and Mitchell Energy
Corporation
Houston, Texas 77002
Hampshire Energy $4,000,000
Milwaukee, Wisconsin
High-Btu Gas
Crow Tribe of Indians $2,729,393
Washington, D.C. 20036
Texas Eastern Synfuels, Inc. $3,018,000
Houston, Texas 77001
Low/Medium-Btu Gas
Florida Power $1,380,796
St. Petersburg, Florida
33733
General Refractories $ 922,555
Bala Cynwyd, PA 19004
Central Maine Power $3,624,558
Augusta, Maine 04336
Feasibility study of gasification of in-situ deep
Texas lignite and conversion of remaining medium-
Btu synthesis gas to methanol and high octane
gasoline.
Site: Texas Gulf Coast
Ten-month feasibility study of converting 15,000
tons/day of coal to 20,000 barrels/day of gasoline,
Site: Gillette, Wyoming
Nine-month feasibility study, high-Btu gas (Lurgi
process - SNG) at Crow Reservation, Montana.
Site: East of Billings, Montana.
Nine-month feasibility study, high-Btu gas (Lurgi
process - SNG, methanol) at San Juan County, New
Mexico.
Site: East of Navajo Indian Reservation
Twelve-month feasibility study of medium-Btu gas
combined cycle.
Site: Pinellas County, Florida
Nine-month feasibility study of low-Btu industrial
fuel gas.
Site: Florence, Kentucky
Fifteen-month feasibility study of combined cycle,
medium-Btu gas at Sears Island, ME. (Process:
Texaco gasifier)
Site: Waldo County, Maine
-------
FEASIBILITY STUDY GRANTS (CONTINUED)
TECHNOLOGY
REQUESTED FROM DOE
DESCRIPTION/SITE
o
i
en
EG&G $4,000,000
Wesley, Massachusetts
02181
Philadelphia Gas Works $1,168,108
Philadelphia, PA 19102
Celanese Corp. Mo Cost
Dallas, Texas 75247
Union Carbide/Linde $3,945,676
Division
Tonawanda, New York 14150
Oil Shale
Gary Energy Corp. $3,009,399
Fruita, Colorado 81521
Transco Energy Co. $3,778,267
Houston, Texas
Tar Sands
Natomas Energy Co. $ 357,511
San Francisco,
California 94108
Standard Oil of Indiana $0
Chicago, Illinois 60601
Feasibility study for a medium-Btu gasification
facility producing combined cycle power and methanol
Choice of process technologies between Koppers-
Totzek or slagging Lurgi.
Site: Fall River, Massachusetts
Twelve-month feasibility study of medium-Btu gas
(Process: TRD).
Site: Philadelphia, Pennsylvania
Feasibility study to determine the technical and
economic viability of developing a carbon monoxide
and hydrogen syngas from either a high-Btu coal
or a Texas lignite.
Site: Near Bishop, Texas
Eighteen-month feasibility study of low-/medium-
Btu gas.
Site: Texas City, Houston, Texas
Feasibility study for upgrading crude oil shale to
gasoline jet fuels, DFI1, and residual using UOP
hydro-processing and hydro-cracking.
Site: Fruita, Colorado
Eighteen-month feasibility of 2000-BPD (or larger)
module of a 50,000-BPD plant.
Site: Lewis County, Kentucky
Eight-month feasibility study of extracting 20,000
barrels/day of oil from domestic tar sands-bitumen,
Site: Site may be in Utah or California
Feasibility study of a 50,000-barrel/day tar sands
Bitumen facility.
Site: Sunnyside, Utah
(continued)
-------
FEASIBILITY STUDY GRANTS (CONTINUED)
TECHNOLOGY
REQUESTED FROM DOE
DESCRIPTION/SITE
o
i
CTt
Unconventional Gas
Acruex Corporation $ 440,261
Mt. View, California 94042
Seneca Indian Nation $ 896,638
Salamanca, New York 14779
Republic of Texas Coal
Co. and Mitchell Energy
Corp.
Houston, Texas 77002
Mountain Fuel Supply Co. $1,810,762
Salt Lake City, Utah 84139
Peat
Minnesota Gas Co. $3,996,554
Minneapolis, Minnesota
55042
Shale Liquid Upgrading
Union Oil Energy Mining $4,000,000
Los Angeles, CA 90017
Feasibility study of anaerobic digestion of sewer
water to obtain methane.
Site: Possibly Oakland, California
Feasibility study of the recovery of natural gas
from Devonian shales - vertical wells. Methane
from Devonian shale.
Site: Salamanca, New York
Feasibility study of gasification, in-situ deep
Texas lignite, and conversion of remaining medium-
Btu synthesis gas to methanol and high octane gasoline.
Site: Calvert, Robertson County, Texas
Two-year feasibility study
gas in the Pinedale field.
and condensate.
Site: Sublette County, Wyoming
of unconventional natural
Product is natural gas
Nineteen-month feasibility study for the production
of high-Btu substitute natural gas from peat.
Site: Minnesota
Feasibility study for operation of a 10,000 BPD up-
grading plant producing premium quality syncrude.
Site: Grand Valley, Colorado
(continued)
-------
TECHNOLOGY
REQUESTED FROM DOE
Unconventional Gas
U.S. Steel Corporation
$ 600,000
Coal Oil Mixture
Banklich Corporation
$ 989,500
U.S. Steel Corporation proposes to build a collec-
tion and compression system to capture methane from
a mine pre-drainage program. The gas, currently
being vented, will be injected into an interstate
pipeline system for sale. The project will produce
the equivalent of 200 barrels of oil per day. Site
is Oak Grove, Alabama.
Banklick Corporation proposes to design and construct
A Coal Mining Mixture (COM) preparation plant on a
site on Blount Island, Florida owned by the Jackson-
ville Port Authority, and to market the products.
In this proposal, the approach is to first grind
the coal, then mix it with oil and pulverize the
result, and, finally, to mix the product more
thoroughly using ultrasonic agitators. A COM prep-
plant is relatively simple and, in addition to the
above equipment, consists of coal storage and
handling equipment (including a coal pile), oil
and COM piping and storage hardware, and associated
hardware. Coal would be delivered by rail. The
project will produce 6,000 barrels per day.
-------
APPENDIX D
EXISTING MARKETING SYSTEM FOR PETROLEUM
AND NATURAL GAS PRODUCTS
TABLE OF CONTENTS
D.I PETROLEUM PRODUCT DISTRIBUTION AND USE PATTERN D-4
D.I.I Product Transportation Systems D-4
D.I.1.1 Product Pipelines D-7
D.I.1.2 Waterborne Transportation D-13
D.I.1.3 Truck Transportation D-13
D.I.1.4 Railroads D-16
D.I.2 Storage D-18
D.I.3 End Uses D-20
D.2 NATURAL GAS DISTRIBUTION AND USE PATTERN D-20
D.2.1 Sources of Natural Gas D-22
D.2.2 Gas Supply System D-22
D.2.2.1 Gathering, Transmission, and Distribution . . D-?2
D.2.2.2 Gas Flow D 26
D.2.2.3 Storage D-28
D.2.3 Natural Gas End Uses D-28
D.2.3.1 D-31
D.3 PETROCHEMICALS D-31
D.3.1 Background D-32
D.3.2 Major Petrochemicals D-36
D.3.2.1 Sources D-36
D.3.2.2 Transportation D-39
D.3.2.3 Benzene Storage D-41
D-l
-------
0.3.3 Benzene End Use
D-42
D.4 SOURCES OF POLLUTANT EMISSIONS TO THE ENVIRONMENT
FROM CONVENTIONAL FUELS TRANSORT AND STORAGE ......... D-45
D.4.1 Transportation Modes Used for Conventional Fuels . . . D-45
D.4. 1.1 Pipelines .................. D-45
D.4. 1.2 Water Carriers ................ D-47
D.4. 1.3 Tanker Trucks ................ D-49
D.4. 1.4 Railroads .................. 0-59
D.4. 2 Product Storage .................... D-50
REFERENCES .......................... D-51
FIGURES
Number Page
D-l Petroleum Flow Diagram, 1978 ............... D-5
D-2 1978 Crude Oil Movement .................. D-b
D-3 Petroleum Refineries in the United States
and Puerto Rico ...................... D-8
D-4 1974 Refined Petroleum Products: Consumption
and Refinery Capacity by States .............. D-9
D-5 Petroleum Administration for Defense Districts ...... D-10
D-6 Petroleum Products Pipeline Capacities (Thousands
of Barrels Daily, as of December 31, 1978) ........ D-ll
D-7 Commercially Navigable Waterways of
the United States ..................... D-P
D-8 Refined Petroleum Products Supplied by Type
and End Use Sectors .................... D-21
D-9 Major Natural Gas Pipelines (March 31, 1980) ....... D-25
D-10 National Gas Flow Patterns ................ D-27
D-ll Location of Underground Gas Storage ............ D~"
D-12 The U.S. Petrochemical Industry 1978 .......... D-35
D-13 The Flow of Petrochemicals to the Motor
Vehicles Industry ..................... D"37
D-2
-------
TABLES
Number Page
D-l Petroleum Product Transportation Methods D-12
D-2 Interdistrict Movements of Petroleum Products
by Tankers and Barges for First Quarter 1978 D-l5
D-3 Tank Car Movements D-l 7
D-4 Nationwide Inventory and Storage Capacities D-13
D-5 Storage Capacity by PAD District D-l9
D-6 Marketed Production of U.S. Natural Gas 1979 D-23
D-7 Gas Utility Industry Miles of Pipeline and Main
by Type and by Region 1979 D-26
D-8 U.S. Natural Gas Storage Volumes and Capacities D-3C
D-9 U.S. Natural Gas Consumption 1978 D-32
D-10 Gas Utility Large Volume Sales, by Type of
Industry and by Division, 1978 D-33
D-ll Primary Petrochemicals Ranked by Volume
of Production D-34
D-12 U.S. Production of Selected Petrochemicals
Ranked by Vol ume D-38
D-13 Regional/State or Territory Production
of Benzene 1979 D-40
D-14 U.S. Shipment of Crude Products from Coal and
Petroleum Tars - Total Tons Shipped by
Transportation Mode in 1972 D-42
D-15 Benzene Consumption in the U.S. by EPA Regions 1979 . . . D-43
D-16 U.S. Consumption of Benzene and its Major
Derivatives by Selected EPA Regions D-44
D-17 Hydrocarbon Emission Factors for Petroleum
Liquid Transportation Sources D- 46
D-18 Liquid Pipeline Accident Summary 1979 D-48
D-3
-------
This appendix assesses the marketing and transporting systems in
commerce today for petroleum and natural gas products, petrochemical pro-
ducts, and by-products. It identifies the current market infrastructure in
relation to crude product transport, storage, refining, and upgrading;
product and by-product distribution and storage; product and by-product
consumption; and the environmental impacts resulting from the combustion of
these products and by-products.
The purpose of this appendix is to identify the current marketplace
and shipment and storage systems that ultimately will be used for the mix
of conventional and synfuel-derived products and by-products. Current
methods used by industries for distribution, storage, and consumption of
these products are assessed as completely as possible where adequate
resource data were documented and/or obtained from the respective indus-
tries. This assessment provided the background for the assessment of the
likely shale oil- and coal-derived products and by-products use patterns
presented in Sections 3 and 4.
D.I PETROLEUM PRODUCT DISTRIBUTION AND USE PATTERN
This section discusses the following broad categories of petroleum
products: gasoline, middle distillates (e.g., jet fuel, kerosene, distil-
late fuel oil), residual fuel oil, and liquefied petroleum gases (LPG).
Figure D-l is an overview of the "petroleum flow'1 from the crude stage
to the refinery and finally to the consuming sector. It shows that the
current domestic crude oil supply is significantly augmented by imports,
and supplemented somewhat by natural gas plant liquids (NGPL) input, other
hydrocarbon input, and processing gain. Plant condensate imports and
unfinished oil imports also contribute to total refinery input. Total
refinery output plus NGPL direct use and refined product imports constitute
the total refined products supplied (Reference 1).
D.I.I Product Transportation Systems
Petroleum moves from production areas to refining centers and finally
to marketing areas and consumers through a complex network of pipelines,
barges, tankers, tank cars, and tank trucks. Essentially all crude oil
must be refined before end use. Crude petroleum normally is transported to
refineries as directly and cheaply as possible. Pipelines and ocean car-
riers constitute the bulk of crude petroleum transport. Although somewhat
limited with respect to route flexibility, cost efficiency makes them the
most attractive methods (Reference 2). A fairly extensive crude pipeline
system exists in the U.S., but some coastal refinery facilities are not
accessible to the primary crude pipelines. These facilities are serviced
by other modes of transportation, e.g., trucks, water carriers, and rail.
Figure D-2 shows the primary crude oil movement pipelines in the U.S.
today.
Pipelines alone transport more than 70 percent of the crude oil
transported in the U.S. today (Reference 3). Primarily they are servicing
D-4
-------
o
I
CJ1
/ »* «*
*f /
° /
*/ //
/ /«
^ ^
v ^
Figure D-l
Petroleum Flow Diagram, 1973 (tVillion Barrels Per Day)
-------
Figure D-2. 197Q Crude Oil Movement
-------
only the South Central, parts of the Southeastern, Mountain, Great Lakes,
and the upper Great Lakes regions in the U.S. However, petroleum product
pipelines are dispersed throughout the refinery areas to accommodate petro-
leum refineries as much as possible. Petroleum refineries are concentrated
in practically all states in the South Central, Southeastern, Northeastern,
Great Lakes, Western, and Northwestern regions. Figure D-3 illustrates
petroleum refinery locations in the United States and their relative capa-
cities (Reference 4). These refineries are expected to handle a mix of
input consisting of syncrude. A complete listing of refineries in each
state is documented in Oil and Gas Journal, March 24, 1980.
If the crude oil movement shown in Figure D-2 is superimposed over the
refinery locations, certain fairly obvious trends appear. Coastal areas
that also are producing areas handle the bulk of refinery activity. The
Gulf coast area is the receiving point for the bulk of foreign imports and
significant amounts of local crude. Although much of the crude is refined
in the Gulf Coast area, large amounts are pipelined to the Great Lakes
industrial area for refining. Some crude from Canada is also piped down
into the Great Lakes Region. California serves as a refining center for
Alaskan crude shipped by tanker, and for local crude pipelines in the west.
East coast refineries receive crude almost exclusively from ocean-going
tankers. As is most apparent in the east, the end-use consumption require-
ments of many states are much greater than their refinery capacity. Figure
D-4 illustrates this imbalance.
Consequently, refined petroleum products generally flow to the
consumers in the north and east via pipelines, water carriers, motor
carriers, and railroads.
Much of the data regarding the movement of crude and petroleum
products is tabulated according to Petroleum Adminstration for Defense
(PAD) Districts. Figure D-5 shows this geographic breakdown.
D.I.1.1 Product Pipelines
Most product pipelines are common carriers and, as such, are subject
to Interstate Commerce Commission (ICC) and Federal Energy Regulatory
Commission (FERC) regulations. Anyone meeting the pipeline's tariffs and
regulations and requesting shipment should be eligible for service, con-
tingent upon scheduling. Normal pipeline specifications may include pour
point, viscosity, and minimum shipment size. These specifications help
facilitate an optimum flow rate and minimum interface contamination
(Reference 5,6). Petroleum product pipelines carry mostly light products--
gasoline, heating and fuel oils, LPG, kerosene, and jet fuel (Reference 3).
They are dispersed throughout regions in the U.S. with primary concentra-
tion east of the Mississippi to accommodate petroleum refineries and major
end use consumers (see Figure D-6). These product pipelines are expected
to service the synfuel industries discussed in Section 3.
An aggregate volume breakdown of petroleum products transported in the
United States gives pipelines about a 37 percent share. This share is
D-7
-------
o
r
Petroleum
ReflnerlM
tarmtt p«r cibniti d*y
250,000
• or lou
capacity
fj More than
-••250,000
capacity
Figure D-3. Petroleum Refineries in the United States and Puerto Rico
(As o-f January 1, 1978)
-------
Figure D-4.
1974 Refined Petroleum Products:
Capacity by States
Consumption and Refinery
-------
o
I
Figure D-5. Petroleum Administration For Defense Districts
-------
o
I
•FOB PUMPING n FUEL OIL
NATIONAL PETROLEUM COUNCIL
UtttMP
-------
roughly equal to trucks (37 percent), which are used for shorter hauls and
heavy products. A surmiary of the "tons carried" and "percent of total"
transported though pipelines in 1950, 1960, 1970, and 1977 is shown in
Table D-l.
TABLE D-l. PETROLEUM PRODUCT TRANSPORTATION METHODS
Year
Pi pel
Tons3
ines
Percent
of total
Water
Tons
a
Carriers
Percent
of total
Trucks
Rail
Percent
a
Tons
of
total
Tons3
road
Percent
of total
Total
Tonsa
1950
1960
1970
1977K
52.7
140.0
333.1
526.0
12.75
21.31
31.12
36.56
185.
244.
286.
361.
2
2
4
7
44.
37.
26.
25.
85
17
75
14
130.8
242.5
425.2
524.6
31.66
36.93
39.72
36.46
44.4
30.2
25.8
26.4
10.74
4.59
2.41
1.84
413.1
656.9
1,070.5
1,438.7
Tons rounded to nearest million.
p
preliminary.
Source: Adapted from Association of Oil Pipelines, Shifts in Petroleum
Transportation, 1979, Table 3, and previous issues.
In comparing the quantities of petroleum product movement by pipeline
between PADD's, the Gulf Coast (PADD 3) far surpasses all other PAD dis-
tricts as the point of origin of interdistrict product movement. About
2.646 MMBPD of product originates in this district and is transported by
pipeline to three other PADD's. PADD's 1, 2, and 5 receive 1.944 MMBPD,
0.655 MMBPD, and 0.047 MMBPD, respectively (Reference 7). The East Coast
is the destination of nearly two-thirds of the total interdistrict
movement, or 3.174 MMBPD. As synfuel products become available, some of
this product movement is likely to come from coal-derived liquid products
produced in Region III after 1987.
PAD District 3 surpasses all other districts in shipment of gasoline
(1337 MBPD), distillate fuel oil (640 MBPD), jet fuel (221 MBPD), natural
gas liquids (192 MBPD), and kerosene (640 MBPD) (Reference 8).
PAD District 1 receives the greatest quantity of most of the products
shipped from PADD's 2 and 3; gasoline (1117 MBPD), distillate fuel oil (543
MBPD), jet fuel (171 MBPD), natural gas liquids (130 MBPD), and kerosene
(29 MBPD) (Reference 8). PAD District 2 receives the largest share of
petroleum products through pipelines: gasoline (392 MBPD), distillate fuel
oil (205 MBPD), jet fuel (52 MBPD), natural gas liquids (158 MBPD), and
kerosene (8 MBPD) (Reference 8).
D-12
-------
0.1.1.2 Waterborne Transportation
Waterborne transportation is typically broken down into two types:
domestic traffic and foreign traffic. Domestic traffic includes all move-
ment between points in the U.S. and Puerto Rico, generally along coastal
routes and within the 25,000 miles of commercially navigable inland
waterways (Reference 9). Figure D-7 illustrates the extent of our river,
canal, and intracoastal waterways, and channel network. The commercial
waterway system stretches up into the Great Lakes and covers the entire
East Coast. Recently there has been some significant waterborne movement
of crude from Alaska along the West Coast (see Figure D-2). Domestic
movement is primarily by barge (moved by towboat or tugboat), and lake and
coastal tanker. Tank barges are second only to pipeline in the volume of
petroleum moved (Table D-l).
Barges generally range in capacity from 1,000 to 3,000 tons, with tugs
and towboats moving flotillas of up to 200,000 tons. Recent rapid growth
of inland waterborne transportation has resulted in significant equipment
investment and, consequently, a relatively modern fleet.
Ocean-going barges are becoming more popular, and their use is
anticipated to increase in the future. These large barges function much
like self-propelled coastal tankers and are likewise constrained by U.S.
port size limitations.
Domestic refineries were designed to maximize production of gasoline
and other high-priced products. Consequently, the U.S. is forced to import
residual fuel oil in large quantities via ocean tanker (Reference 9). The
imports currently being transported are expected to be displaced to some
extent by synfuels. Generally, pipelines do not carry heavy products such
as residuals. Thus, domestically, barges and tankers often complement
rather than compete with pipelines in moving heavier products (Reference
9).
Waterborne movements are summarized in Table D-2. For more detail
refer to the National Petroleum Council, Petroleum Storage and Transporta-
tion Capacities - Waterborne, Vol. V, December, 1979 (Reference 9). The
Gulf Coast apparently serves as the only significant point of origin for
interdistrict waterborne petroleum product shipments, with the East Coast
receiving the largest share (Reference 6).
Gasoline (50 percent), distillate fuel oil (23 percent), and residual
fuel oil (12 percent) constitute the largest domestic volume movements
(Reference 7). However, when foreign tanker imports are also included in
volume calculations, residual fuel oil is transported in the largest
quantities followed by distillate fuel oil, crude oil, and other products.
D.I.1.3 Truck Transportation
Trucks interface with many different segments of the petroleum
industry. Trucks pick up crudes at the wellhead for delivery to gathering
D-13
-------
MINNEAPOLIS • ST. PAUL
Gulf Intracoastal Waterway
CONTROLLING DEPTHS
mm 9 FEET OR MORE
.... UNDER 9 FEET
Atlantic
Intracoastal
Waterway
SOURCE: Adapted from Flntl Enylronmtnttl Impact St*t«m»r>t. Tit It XI; U.S. Department of Commerce. Maritime Administration. February 1979.
-------
TABLE D-2. INTERDISTRICT MOVEMENTS OF PETROLEUM PRODUCTS BY TANKERS AND BARGES
FOR FIRST QUARTER 1978 (IN THOUSAND BARRELS PER DAY - MBPD)
Origin
Destination
East coast Midcontinent Gulf coast Rocky Mts. West coast
(PADD-1) (PADD-2) (PADD-3) (PADD-4) (PADD-5)
Total
i
en
East coast
(PADD-1)
Midcont inent
(PADD-2)
Gulf coast
(PADD-3)
Rocky Mts.
(PADD-4)
1,213
175
18
1,406
West coast
(PADD-5)
Total
1,213
175
18
1,408
SOURCE—U.S. Department of Energy, 1978 (March), Energy Data Reports.
-------
pipelines or directly to refineries. Direct deliveries from refiners to
distributors are often made by truck. Widespread movement of products to
final consumers is facilitated by tank truck (all gasoline to service
stations is delivered by motor carrier). And finally, truck transport can
provide relief during seasonal peak demand by supplementing product pipe-
line deliveries (Reference 7). In fact, nearly all oil products and LPG
are, at some point, moved by tank truck. But this movement is difficult to
track and document because the brevity of the hauls (generally 50 miles or
less) and the extent of our highway system (Reference 2).
Although tank trucks are used extensively for short hauls, they have
only limited potential for long-haul shipments. Table D-l indicated that
truck transport has grown faster than any other method of petroleum trans-
port. Much of this growth has been at the expense of the railroads, which
cannot compete with the lower capital requirements, scheduling, and route
flexibility inherent in the trucking sector (Reference 2,7). Truck adapt-
ability has given motor carriers an estimated 37 percent of the petroleum
transporting industry—essential ly equal to pipelines (37 percent as shown
in Table D-l).
Thus, as synfuel production develops, trucks are expected to be the
initial mode of product transport, especially in Region VIII. Also, trucks
are expected to play an increasing role in product movement for short hauls
and in areas where pipeline networks are unavailable.
Unfortunately, information on motor carriers is sketchy at best,
indicating an area for further investigation. Although the industry is
regulated by three government agencies — the Interstate Commerce Commission,
the Bureau of Motor Carrier Safety, and the Materials Transportation Bureau
(the latter two both within DOT)--very little volume movement is tabulated.
New tank trucks are becoming progressively lighter and stronger with
the use of aluminum alloys, stainless steel and reinforced fiber glass.
Lighter weight permits greater payload size, with capacities reaching
11,000 gallons.
Trucks using the interstate highways must meet ICC specifications. In
particular, LPG carriers are strictly regulated because of the potential
for explosion. The statistics reported by the Energy Information Admin-
stration and the NGPLA indicate that trucks accounted for 3.4 and 3.5
percent of the total LPG transported during 1977 and 1978. Other modes of
transport during this time include: pipeline-truck 90.6 and 90.3 percent,
pipeline-rail 4.6 and 4.4 percent, rail 0.9 and 1.5 percent, and tanker or
barge 0.5 and 0.3 percent. As older trucks are retired, lighter, larger
ones will be coming into service resulting in continued stability or growth
in product volume movements.
D.I.1.4 Railroads
Rail transport constitutes the smallest market share with only about I
percent in 1977 (see Table D-l). For some products (petrochemicals and
D-16
-------
liquefied petroleum gases) rail is still a practical method of transpor-
ting. Small volumes (8,000 to 34,000 gallons) can be delivered by single
cars. The unit train concept (connected tank cars) allows large-volume
movements. But at present, the greatest volume of intermediate and long-
distance shipment is done by barge, tanker, and pipeline, rather than rail.
Railroad petroleum product shipments are reported annually by the ICC.
Liquefied petroleum gases and coal gases are moved in the greatest volumes
followed by residual fuel oil, asphalts, and lubricating oils (Reference
2).
A 1977 Interstate Commerce Commission (ICC) one percent waybill sample
of tank car movements indicates a concentration of car movement origins in
PAD Districts 1, 2, and 3. This data is summarized in Table D-3. PADD 3
has the most significant amount of traffic with the Texas-Louisiana
refining area carrying the highest percentage of car loads. In PAD
Districts 4 and 5, where the rail system is not as extensive as in the
east, the number of car load shipments is relatively small (Reference 10).
TABLE D-3. TANK CAR MOVEMENTS
Origin
PADD 1
PADD 2
PADD 3
PADD 4
PADD 5
Number of
Carloads
2,414
3,234
4,524
437
610
Percentage of
Total Carloads
21.47
28.80
40.39
3.90
5.43
Tons
167,213
220,500
337,924
34,705
47,399
A number of different types of tank cars are equipped with heating
coils or insulation with capacities ranging up to 50,000 gallons or more.
Unpressurized, unheated cars are usually used for aviation fuels, gaso-
lines, and distillate fuel oils. Pressurized cars carry LPG such as pro-
pane and butane. Cars with heating coils keep heavy fuels and asphalts
viscous. Thus, due to design specifications, individual cars may require
costly alterations in order to be used to carry different products
(Reference 2).
Tank cars must meet ICC and DOT specifications and their speed is
constrained by the condition of the rails themselves. Use of new materials
has resulted in weight reductions and cars more suited to transporting
corrosive products (Reference 2). Railroads may regain part of the petro-
leum transportation market if the unit-train concept (likened to a mini-
Pipeline on wheels) becomes feasible and competitive and as synfuel
products become available.
D-17
-------
D.I.2 Storage
Petroleum products are stored at many points in the distribution
network. A tabulation of stocks could include products in tank cars at
railroad sidings, pipeline fill, refinery inventory, and bulk terminal
storage.
Inventory exists within the system as part of normal or anticipated
fluctuation in distribution and refining activities. But actual tank
storage facilities serve many additional purposes, including:
• Receiving and holding shipments that are delivered in discrete
parcels but used continuously
• Accumulating products in anticipation of pipeline or waterborne
movement
• Segregating different grades
• Holding crude and products during system maintenance
f Handling unavoidable but anticipated events
• Meeting safety and design specifications (Reference 10).
Table D-4 summarizes the results of a nationwide survey examining
ivnentories and storage capacities.
TABLE D-4. NATIONWIDE INVENTORY AND STORAGE CAPACITIES
Primary Distribution
System Minimum Operating a
Inventory Storage Capacity
Product (millions of barrels) (millions in barrels)
Crude Oil 290 462
Gasoline 210 438
Kerosene 35 90
Distillate Fuel Oil 125 365
Residual Fuel Oil 60 162
Source: National Petroleum Council
Storage Capacity: Shell capacity of tankage and unavailable inventory
outside of tankage
Somewhere between minimum operating inventory and total storage
capacity is the actual measure of stocks. With products such as gasoline
and jet fuel, storage at the refinery is nearly equal to bulk terminal
D-18
-------
storage (50,000 barrels). Kerosene, distillate fuel oil, and residual fuel
oils are stored in greater quantities at bulk terminals.
A detailed breakdown of inventory and storage capacity as of September
30, 1978 is documented in the National Petroleum Council, Petroleum Storage
and Transportation Capacities-Inventory and Storage, Vol. II, December
1979. (Reference 12).Table D-5 summarizes the storage capacity of each
PAD district (Reference 5).
TABLE D-5.
STORAGE CAPACITY BY PAD DISTRICT
(000 BARRELS)3
Product
PADD1
PADD2
PADD'
PADD
PADD'
Crude Oil
Gasoline
Kerosene
Distillate
Fuel Oil
Residual
Fuel Oil
3,941
122,593
31,066
144,193
54,727
92,296
132,598
20,618
100,342
17,096
160,077
113,138
21,537
61,775
23,576
21,010
16,361
1,721
6,253
2,450
51,588
49,007
14,425
20,634
24,152
Storage Capacity Shell
outside of tankage
capacity tankage plus unavailable inventory
PADD 1 has very little crude oil storage, probably because of the lack
of crude pipelines and refining facilities. The industrial Middle-Atlantic
region in PADD 1, however, has the greatest product storage capacities
(356.5 MMBBL) compared to other PADDS. PADD 2, an area with much crude
movement and refining, has extensive crude and product storage (largest)
followed by PADD's 3 and 1 respectively. The Texas Gulf Area of PADD 3
has, of course, the greatest storage capacity for crude and relatively high
product storage capacity (third largest) in preparation for product
movement out of the area. PADD 4 has relatively small storage capacities
to date because it is not industrialized and has only immature production
capability. PADD 5 has moderate crude and product storage capabilities.
A detailed listing of refinery capacities by state is documented in
Qjl and Gas Journal , March 24, 1980. Further information on terminal
capacities may be obtained from the Independent Liquid Terminals Associa-
tion's 1980 Directory,Bu1k of Liquid Terminals and Storage Facilities.
In addition to primary storage facilites, significant capacities exist
in the secondary/consumer storage system. Although it is difficult to
determine, estimates put storage in this segment at 500 million barrels for
Qasoline and distillate fuel oil. This is about 60 percent of primary
D-19
-------
storage capacity. Movements and concurrent shortages and surpluses between
these two systems warrant examination (Reference 5).
D.I.3 End Uses
Petroleum products are used everyday in a number of ways. The most
recognizable form, gasoline, constitutes over one-third of all refined
products, and supplies the largest petroleum end use sector--
transportation.
In 1979, motor gasoline was supplied in the greatest aggregate volume
(7.03 MMBPD), followed by distillate fuel oil (3.30 MMBPD), residual fuel
oil (2.79 MMBPD), jet fuel (1.07 MMBPD), and kerosene (0.18 MMBPD). The
"other products" category constitutes a large volume but includes over 2000
different refined products (Reference 1).
These petroleum products flow into a number of different sectors
including transporation, electric utilities, industrial, and residential-
commercial. The transportation sector is the greatest end use of refined
products (9.72 MMBPD) followed by industrial (3.65 MMBPD), residential-
commercial (3.45 MMBPD), and electric utilities (1.55 MMBPD) (Reference 1).
In this sector synfuels are likely to displace products currently being
supplied by imports. Likely target areas for synfuel products are Region
VIII during the initial development with other regions, i.e., Region III,
another likely target area as development moves toward the eastern part of
the U.S. Figure D-8 summarizes refined products and end users together for
1977-1979. Although gasoline and jet fuel account for the greatest
quantities consumed in the transportation sector, residual and distillate
fuel oils also are consumed for transportation as well as the other sec-
tors. Liquefied gases are used in the residential-commercial sector as
well as the industrial. While varying amounts of "other products" are used
in all sectors, the industrial sector consumes the largest quantities of
the varied product slate.
A tabulation of products and corresponding end users for each state is
documented in detail in the Energy Information Administration, State Energy
Data Report, April 1980 (Reference 13). The tabulation confirms the gen-
eral description of petroleum product flow to end users, but may be used to
isolate peculiarities in particular states.
D.2 NATURAL GAS DISTRIBUTION AND USE PATTERN
This section examines the U.S. natural gas system infrastructure.
Because of the extensiveness of the U.S. natural gas system and the recent
legislative activities associated with synfuel development, the U.S.
natural gas system has been assured of a role in the development of
synthetic fuels, more specifically, the transmission and use of substitute
natural gas (SNG).
Since little is presently known concerning the hazards of SNG from
differing gasification technologies, an assessment of potential areas of
D-20
-------
o
I
at
ffl
03
C
o
m
Other
Liquefied Gases
Residual Fuel Oil
Distillate Fuel Oil
Jet Fuel
Motor Gasoline
c
o
(0
C
o
a
w
c
CO
c
o
1
o
a
ca
to
1 g
5 «
®C
T3 E
55 E
(DO
oc o
w
3
CO
'5
k.
E
E
o
O
•o
c
CO
"55
a
«
(0
D
_o
*C
_«
LU
1977 1978 1979
Source: Energy Information Administration, Annual Report to Congress, 1979.
Figure D-8. Refined Petroleum Products Supplied by Type and End Use Sectors
-------
exposure is needed to properly monitor and control pollutants at acceptable
levels. Towards this end, this section examines the existing U.S. natural
gas system by assessing the sources of natural gas, its distribution to
consumers, and its end use consumption pattern.
D.2.1 Sources of Natural Gas
Naturally occurring gas, which is found in porous and permeable
reservoirs beneath the earth's surface, has been the mainstay of U.S.
natural gas production since its inception. Historically, U.S. natural gas
has been supplied from well-known, generalized areas (see Figure D-9). The
largest production area is in southern Louisiana and the Gulf Coast area,
which produced more than 36 percent of U.S. domestic gas in 1979. Other
major gas producing fields are located in Texas, Oklahoma, New Mexico, and
Kansas. In total, these areas are responsible for 90 percent of the U.S.
natural gas production (see Table D-6).
D.2.2 Gas Supply System
D.2.2.1 Gathering, Transmission, and Distribution
Natural gas is normally purchased by gas pipeline companies from
production companies in the gas fields. The gas pipeline companies then
transport the gas to the market area where it is sold to distribution
companies which make deliveries to the end-use customers. This system
consists of a gathering, transmission, and distribution network (see Table
D-7).
The gathering segment consists of a grid of pipelines spreading
throughout the gas producing fields. This pipeline grid gathers gas from
the wells and/or processing plants and funnels it into the main transmis-
sion line portion of the system through the use of compressor stations
where needed.
The main transmission line portion of the system usually consists of a
single line, and at most five parallel lines, with compressor stations
every 40 to 130 miles.This main transmission line spans the distance
between the gas field and the market area (see Figure D-9).
After reaching the market area, the gas is sold and delivered to
various distribution companies, local utilities, or industrial customers.
Often the delivery points are located directly on the main transmission
line, but it is common for deliveries to be made through a lateral line
that branches out to the buyer's distribution system.
D-22
-------
TABLE D-6. MARKETED PRODUCTION OF U.S. NATURAL GAS 1979
Region
Region I
Region II
Region III
Region IV
Region V
Region VI
States Covered
Connecticut
Maine
Massachusetts
New Hampshire
Rhode Island
Vermont
Total
New Jersey
New York
Total
Delaware
District of Columbia
Maryland
Pennsylvania
Virginia
West Virginia
Total
Alabama
Florida
Georgia
Kentucky
Mississippi
North Carolina
South Carolina
Tennessee
T i ^
Total
111 inois
Indiana
Michigan
Minnesota
Ohio
Wisconsin
iota i
Arkansas
Louisiana
New Mexico
Oklahoma
Texas Total
Capacity
(Millions of ft3)
0
0
0
0
0
0
nr
0
10,460
10,460
0
0
80
89,810
8,049
149,590
247,529
56,037
47,169
0
59,635
81,269
0
9
258
244,377
982
179
127,251
0
97,261
0
225,673
101,931
7,064,958
1,177,955
1,732,719
6,904,389
16,981,952
(continued)
D-23
-------
TABLE D-6. (CONTINUED)
Capacity
Region States Covered
Region VII Iowa
Kansas
Missouri
Nebraska
Total
Region VIII Colorado
Montana
North Dakota
South Dakota
Utah
Wyoming
Total
Region IX Arizona
California
Hawa i i
Nevada
Total
Region X Alaska
Idaho
Oregon
Washington
Total
Total U.S.
(Millions of ft3)
0
765,039
20
2,731
767,790
184,866
45,845
28,566
0
59,434
323,313
642,024
235
304,985
0
0
305,220
183,982
0
0
0
183,982
19,609,000b
NOTE: Marketed production Total gas produced (repressuring, vented,
flared); Data represent actual 1979 U.S. marketed total production
broken down by 1977 production percentages.
Totals may not equal sums due to independent rounding.
Source: Adapted from Gas Facts 1978, AGA, 1979; Monthly Energy Review^
DOE/EIA 0035, February 1980.
D-24
-------
o
I
ro
en
AlJENERCY REGULATOR?'COMMESIO
Figure D-9. Major Natural Gas Pipelines (March 31, 1980)
-------
TABLE D-7. GAS UTILITY INDUSTRY MILES OF PIPELINE AND MAIN
BY TYPE AND BY REGION 19793'
Region
I
II
III
IV
V
VI
VII
VIII
IX
X
Total
U.S.
Total
26,632
62,842
95,329
130,605
210,518
227,683
88,105
49,408
96,673
25,281
1,013,076
Field and
Gathering
0
412
14,566
3,888
4,398
35,602
8,123
7,038
853
18
74,898
Transmission
Pipeline
1,644
5,021
20,813
39,791
39,841
86,141
33,290
15,560
14,152
4,394
260,647
Distribution
Main
24,988
57,409
59,950
86,926
166,279
105,940
46,692
26,810
81,667
20,869
677,530
Excludes service pipe. Data not adjusted to common diameter equivalent.
Milage shown as of end of year.
Includes 6,000 miles of underground storage pipe.
Source: American Gas Association, Gas Facts 1978, 1979, p.56.
D.2.2.2 Gas Flow
Production volumes and the gas supply system can be combined to show
the relative distribution of natural gas flow throughout the U.S. Briefly,
large amounts of gas from the major producing fields of Louisiana, Texas,
and Oklahoma are shipped northward to the major markets of the Great Lakes
region and northeastern U.S. The Great Lakes region is also supplied by
imports from Canada. Major markets in California are supplied by gas
flowing westward from production fields in New Mexico and western Texas.
In addition, significant gas volumes flow southward from Canada into
Washington, Oregon, and on into California (see Figure D-10). Changes in
gas flow patterns in response to synthetic natural gas produced from coal
cannot be predicted because the actual locations of coal gasification
plants are still uncertain. Section 3.1.2, however, does discuss these
facilities as being located where they have access to the existing pipeline
network. Therefore, it is expected that the existing transmission system
will be utilized through spur pipeline connections to these gasification
plants.
D-26
-------
o
I
ro
tUIIUUM Of VON riOW CAMCIT*
AVIMGI H" 0«ll» »IOWWO
VOIUM<»
0 KMI
Figure D-10. National Gas Flow Patterns
-------
D.2.2.3 Storage
Underground gas storage is a principal factor in gas operations.
Storage involves transporting gas from producing fields and reinjecting it
into other reservoirs where it is stored until needed to meet market
requirements. Approximately 40 percent of the natural gas consumed
annually by residential space heating customers in the U.S. has been
withdrawn from underground storage (Reference 14).
Because storage facilities are used to augment the supply of gas used
during the colder months of the year resulting from increased space
heating, most storage facilities are located near the major consumption
areas. However, many storage areas are located near the major producing
areas of Louisiana, Texas, Oklahoma, Arkansas, and Kansas (see Figure
D-ll).
The U.S. has an ultimate reservoir capacity of 7,330 billion cubic
feet distributed among 385 individual underground storage facilities
located throughout 26 states. There are three types of storage facilities:
depleted gas or oil fields, waterbearing sands, or salt domes.
The largest concentration of storage facilities exists within Region V
(Illinois, Indiana, Michigan, Minnesota, Ohio, and Wisconsin), which is
also a major natural gas consumption area. In total, 38 percent of U.S.
natural gas reservoir capacity is located in Region V. The next largest
concentration of storage facilities is in Region III (Delaware, District of
Columbia, Maryland, Pennsylvania, Virginia, and West Virginia). Storage
capacity in Region III amounts to 18 percent of the U.S. total. The
remaining 44 percent of storage capacity exists in Region VI 17 percent,
Region VII 9 percent, Region IX 7 percent, Region VIII 5 percent,
Region IV 4 percent, Region II 2 percent, and Region X about 0.4
percent. No storage capacity exists in Region I (see Table D-8).
D.2.3 Natural Gas End Uses
Natural gas is used primarily as a fuel resource. However, its
gaseous hydrocarbon compounds such as ethane, butane, and propane are used
by the petrochemical industry for feedstocks as well. The total volume of
natural gas consumption in 1978 totaled 19,624 billion cubic feet, which is
nearly 26 percent of domestic energy consumption (Reference 15). Natural
gas ranks second in the domestic market share of energy consumption behind
petroleum.
D-28
-------
o
I
ro
10
HOI I Cvctetf
Source: Petroleum Storage and Transportation Capacities, Gas Pipeline.
Vol. VI, National Petroleum Council, December, 1979.
Figure D-ll. Location of Underground Gas Storage
-------
TABLE D-8. U.S. NATURAL GAS STORAGE VOLUMES AND CAPACITIES
Maximum Stored Ultimate Reservoir
Gas 1979a ~ Capacity 1978°
Region (Billions of FtJ) (Billions of FtJ)
I
II
III
IV
V
VI
VII
VIII
IX
X
147
1,398
350
2,432
1,052
535
257
355
38
0
151
1,330
314
2,761
1,231
642
368
503
31
Total U.S.C 6,563 7,330
a Maximum U.S. stored gas obtained from DOE/EIA 0035/02 (80) Monthly Energy
Review, p.50. State and division data obtained by multiplying percentage
of maximum stored gas in 1978 (Source: AGA, Gas Facts 1978, p.48, 1979)
times the 1979 U.S. maximum stored gas.
b Source: AGA, Gas Facts 1978, p.48, 1979
c Total may not equal sums because of independent rounding.
The largest single end use of natural gas is space heating.
Residential and commercial services combined are the major consumers of
natural gas for space heating, which accounts for more than 38 percent of
natural gas consumption in these sectors. Such a large market share was
brought about by the installation of gas furnaces in new homes and con-
versions to natural gas from coal and heating systems which resulted in
annual growth rates of 4.5 percent prior to the 1970's; however, government
restrictions have since limited growth because of declining natural gas
reserves (Reference 16).
The largest consumer of natural gas by class of service is the
industrial sector. Industrial consumption amounted to almost 43 percent of
the total gas sales in 1978. The five largest consumers, which amassed 60
percent of industrial gas sales, were: (1) electrical services, (2) chemi-
cals and allied products, (3) primary iron and steel, (4) food and kindred
products, and (5) fabricated metal products, machinery equipment, and
supplies.
D-30
-------
It is expected that electric utilities and other industrial users of
natural gas will shift increasingly to sources of low-Btu synthetic gas
production as shortages of natural gas become increasingly acute. This
will result in consumption of low-Btu synthetic gas near the point of its
production because it cannot be transported economically over long dis-
tances by pipeline. Consequently, this will leave natural gas and high-Btu
synthetic gas production primarily to residential and commercial users.
D.2.3.1 Geographical Areas of End Use
Three major market areas account for 69 percent of the consumption of
natural gas in the U.S.: Region VI {Arkansas, Louisiana, New Mexico,
Oklahoma, and Texas); Region V (Illinois, Indiana, Michigan, Minnesota,
Ohio, and Wisconsin); and Region IX (Arizona, California, Hawaii, and
Nevada).
Industrial use amounts to 56 percent of total natural gas consumption
in the south central region, Region VI. Electrical generation services are
the largest industrial consumers by sales, followed by: (1) chemicals and
allied products, (2) petroleum refining, (3) petroleum and natural gas
production, and (4) paper and allied products.
The Great Lakes states of Region V (Illinois, Indiana, Michigan,
Minnesota, Ohio, and Wisconsin) constitute the next largest natural gas
consumption region with 20 percent of the total U.S. natural gas consump-
tion. Residential and commercial use is the largest consumer followed by
industral service. The five largest industrial users in this area by sales
are: (1) primary iron and steel, (2) other services, (3) fabricated metal
products, machinery, equipment and supplies, (4) chemicals and allied
products, and (5) food and kindred products (see Tables D-9 and D-10).
The western states of Region IX (Arizona, California, Hawaii, and
Nevada) are the third largest consumption areas of natural gas. Together
they account for 9 percent of the natural gas consumption. Residential and
commercial use are the largest consumers followed by industrial use. The
five largest industrial consumers by sales are as follows: (1) electrical
services, (2) petroleum refining, (3) food and kindred products, (4)
chemicals and allied products, and (5) other services.
D.3 PETROCHEMICALS
This section is primarily concerned with the assessment of the current
existing marketing system infrastructure associated with the production and
distribution of petrochemical products and by-products derived from petro-
leum and natural gas feedstocks. The assessment puts into perspective the
types and relative quantities of petroleum-based products and by-products
that are in commerce today. In addition, this assessment serves as the
framework for the baseline marketing system into which oil shale and coal-
derived synfuel products and by-products are introduced into the
petrochemical industry as they become available.
D-31
-------
TABLE D-9. U.S. NATURAL GAS CONSUMPTION 1978 (MILLIONS OF Ft3)
Region Residential Commercial Industrial
Trans- Electric
portation Utilities
Total
I
II
III
IV
V
VI
VII
VIII
IX
X
Total
U.S.
138,052
467,315
484,657
392,860
1,669,674
514,692
387,494
203,976
579,305
64,981
4,903,006
71,847
190,993
219,011
269,224
796,353
340,293
253,148
131,110
270,962
58,165
2,601,106
50,725
134,346
390,703
660,401
1,442,010
4,323,245
391,074
232,493
544,283
235,329
8,404,609
646
806
44,244
91,051
35,960
209,236
81,456
14,521
29,874
19,655
527,449
1,596
1,992
3,459
220,580
75,034
2,277,784
166,359
38,682
378,295
24,525
3,188,306
262,866
795,452
1,142,074
1,634,116
4,019,031
7,665,250
1,279,531
620,782
1,802,719
402,655
19,624,476
Source: Energy Information Administration, State Energy Data Report,
April, 1980.
Because the petrochemical industry encompasses a diversity of
hydrocarbon chemical compounds (i.e., primary petrochemicals, petrochemical
intermediates, petrochemical products, and petrochemical by-products), it
was necessary to limit the scope of this assessment to only the following
selected primary petrochemicals: ethylene, propylene, benzene-toluene-
xylene (B-T-X) group, and butadiene. The selection of these six petro-
chemicals was based on their being the primary petrochemicals, and on their
significant use in the production of petrochemical intermediates, products,
and by-products. Table D-ll gives the U.S. production rate (billions of
Ib) of the six selected primary petrochemicals, and ranks them according to
the volume of production reported for 1979.
D.3.1 Background
The definition of petrochemicals varies widely in the literature
depending on the purpose of the statistics reported. The general defini-
tion is that petrochemicals include all chemical compounds derived from
crude oil and natural gas hydrocarbons. These compounds include a variety
of petrochemicals (ethylene, propylene, benzene, toluene, xylene, and
butadiene) and intermediate organic compounds that are converted in down-
stream processes into such petrochemical products as synthetic fibers,
plastics, synthetic rubber, medicinals, nitrogen fertilizers, pesticides,
and industrial solvents (Reference 17, 18, 19). However, the literature
D-32
-------
TABLE D-10.
GAS UTILITY LARGE VOLUME SALES, BY TYPE OF INDUSTRY
AND BY DIVISION, 1978 (BILLIONS OF Ft3)
o
i
CO
OJ
Industry Classification
Agricuhare. forestry and fithenes
Petroleum and uniral gas production
Other mining
Y^M li^ unjiiWM
Other transportation, eommunication.
and public utilities
Hotels, rooming houses, and camps
Laundries, cteuing and dyeing
Other services
Other non-manufacturing
Food and kindred producu
Textile producu. apparel, fabnci etc.
Fumitutt. lumber, and other »ood product!
Paper and allied producu
Carbon black
Chemicals and allied producu Icicept carbon black)
Petroleum refining
Rubber and mbceUaaceas pUstic producu
CUsa producu
Cement
Clay producu. potter-, etc
Other none producu and miscellaneous
Primary iron and steel industries
Primary non-ferrous industries
Fabricated metal products, machinery
equipment and supplies
Transportation equipment
Other manufacturing
Public administration
Teanl (Som)b
TeMl Claim ii rial. MostruU and -Other" aalea
el e*.'a mporttng Ihlt labU
Total CM ttfllrj MM? Commercial.
WnatrUI^-OU^-MU.
Total
U.S.
28.5
42.9
41.5
1,495.8
76.5
21.5
181
269.8
139.2
2673
367
42.0
193.7
32.8
589.7
236.4
40J
170.9
57.2
83.3
90.3
561.3
2024
248.1
989
113.4
56.0
5,253.8
7,377.0
9,647.8
New
0.0
0.0
a
6.3
1.8
O.I
a
1.2
OJ
IJ
1.6
a
0.7
a
1.3
0.2
0.4
1.7
O.I
a
1.7
4.7
0.7
5.0
0.8
1.4
0.4
33.7
99.5
127.0
Middk
Atlantic
O.I
0.0
0.4
3.3
1.0
1.7
0.2
9.3
II 6
9.4
1 9
0.9
9.4
0.0
18.7
5.2
3 1
42.0
a
9.9
8.0
1027
II 2
38.6
10.4
II 7
2.9
315.6
644.5
735.4
East
North
Central
6.1
a
3.0
56.8
23.2
10.0
9.7
155.8
75.5
101 6
3.S
8.1
54.8
1 0
1230
II 1
180
5' 2
29
16.8
22.8
3107
73.8
1444
62.0
40.2
170
1,409.7
1,814.5
2.161.2
West
North
Central
7.7
4.4
0.4
135.9
14.8
0.3
0.1
15.3
2.8
43.2
0.3
0.8
3.8
21.5
93.9
16.1
3.2
10.9
13.6
6.2
9.2
31.0
12.5
16.7
83
152
3.6
491.6
779.4
931 6
South
Atlantic
a
•
a
52.3
0.9
1.0
0.4
8.2
2.0
12.1
17.1
1.6
18.5
2.1
r.6
4.8
0.7
I8.S
138
23.5
14.0
216
8.6
51
3.S
5.8
100
333.9
561.9
721.1
East
South
Central
0.2
I.I
0.4
19.0
0.5
0.0
0.1
4.4
4.3
5.7
5.5
5.7
33.5
0.0
39.0
6.8
4.7
8.2
4.2
8.4
3.8
39.5
18.1
11.5
2.7
15.2
1.5
243.9
341.7
484.9
West
South
Central
5.0
23.4
8.7
740.7
13.0
1.7
0.2
14.1
0.7
11.8
0.5
8.0
19.5
7.0
131 8
87.6
2.7
9.8
6.6
2.1
3.8
2.5
63
3 1
0.6
4.4
1.9
1,117.3
1445.6
1.757.0
Mountain
1.9
81
21 7
173.2
6.0
0.5
0.0
11.5
9.8
18.7
a
1.5
13.4
0.0
39.3
15 S
2.2
1.0
94
5.0
2.9
234
490
2.8
0.3
32
76
427.9
561.8
624.7
PadrV
7.4
5.9
7.0
308.3
13.4
S.2
7J
49.0
32.2
43.5
6.1
15.4
40.0
1.2
S4J
88.4
SJ
21.5
6.7
11.2
24.1
2S.2
224
20.9
10.5
16.3
11.3
880.0
1,028.1
1.102.8
a Lett than u Ui
b Includa th< following quantnm of gas for elecnc genernwn not included in Total Commend!. Induitnal and "Other" talci of companies reporting thn table or at Toul Cai UliKt) Induflrjr utei Suet
quantities repmeni iranrfcn b> (he fii department to the electric department of combination gu and electric companies
0.0 2.5 49 30.6 4.6 1.7 111.) 32.5 0.0
Source: American Gas Association, Gas Facts 1978, p. 92, 1979.
-------
TABLE D-ll. PRIMARY PETROCHEMICALS RANKED BY VOLUME OF PRODUCTION
Petrochemical Production (109 lb)a
Ethylene
Propylene
Benzene
Tol ueng
Xylene
Butadiene (1,3)
TOTAL U.S.
29.19
14.30
12.72
11.86
11.07
3.55
82.69
Quantities reported for 1979 production in C+EN, May 5, 1980
All grades including p-xylene 4.18 and xylene 6.89
Rubber grade
Source: "C&EN's Top Fifty Chemical Products and Producers Special Report,"
Chemical and Engineering News, May 5, 1980, pp. 33-37.
states that "there is no standardized definition of the petrochemical
industry" {Reference 17, 20).
The U.S. was the early pioneer of the petrochemical industry, which
began its most rapid growth during World War II. Much of the growth in the
first-stage operations of the industry, which involved production of pri-
mary petrochemicals, was concentrated along the U.S. Gulf Coast states {EPA
Region VI) where abundant supplies of petroleum and natural gas raw
materials/feedstocks existed. Production of these primary petrochemicals
is still concentrated in Region VI, and the states of Texas and Louisiana
account for about 70 percent of all primary petrochemical production
(Reference 21).
The petrocehmical industry can be briefly characterized as that
portion of the chemical and allied products industries that utilizes cer-
tain petroleum and natural gas fractions and converts these feedstocks into
a wide variety of primary petrochemicals. These primary products are then
transferred to other sectors of the petrochemical industry throughout the
U.S. for conversion to petrochemical intermediates, and to such petro-
chemical products as synthetic fibers, plastics, synthetic rubber, etc.
These products, in turn, are fabricated by many different industries into
thousands of consumer products (Reference 21). Five of the selected
primary petrochemicals are shown in Figure D-12 in relation to how the
industry derives primary petrochemicals and petrochemical products from
petroleum and natural gas feedstocks. The figure also shows the major
consuming industries and direct end uses of the final products. Figure
D-34
-------
Fwdnocfca
Induitrln
O
I
u>
tn
Petroleum
1
Naphtha
Gil Oil
i
i
Ethane
Propane
Bulanei
NMuf *l 0*1
Ethy'ene
28 Ulllon
pound!
Propytene
14 billion
poundi
Butadiene
4 billion
poundi
Beniene
11 billion
poundi
P-nylene
3 billion
poundi
Ammonia
35 billion
poundi
•
Plaitldpn
Dyeituffi and
Pigment!
Industrial
Organic
Chemical!
SIC-28C5. 2869
Salei: $30 billion
Solvent!
Rubbor
Proonlnf
Chemlcali
Peitlcidet
•V
Plaitlc Reiln
SIC 2821
Salei $11.4 billion
Fabricated Plaitln
SIC 3079
Salei S2J? billion
Nitrogen Fertilizers
SIC 2873
Salei $2.5 billion
Fertiliser Material!
SIC 287S
Solei S2 billion
Pick aging
Building & Conrauctton
Trinioortatlon
KouKwarn.
Furniture,
Appliance!
Synthetic Fiber!
SIC 2824
Salei $5.9 billion
Textile Mill Product!
SIC 22
Salei $40 billion
Apparel
Upholitry Fabric
Tire Cord
Surface Active
Agenti
SIC 2843
Salei $1.0 billion
SoifH & Detergent!
SIC2S41
Salei $0 billion
Industrial
& Coniumtr Otanrnf
Compound!
Synthetic Rubber
SIC 2822
Salei $2.4 billion
Rubber Product!
SIC 301 -308
Silei $16 billion
Tlrei
Bclttnf
How
Medicinal!
SIC 2822
SaleiS 1.7 billion
Pharmaceutical!
SIC 2834
Salei $12 billion
H Ethical and
Proprietary
Drug!
•Crop)
Petrochemical Purchapri
Fefdstoeki. Fuel
Raw Material! tnd Supptlei
$13.0 Billion
Petrochemical Induilry
Value Added
-t^ J23.2 Billion
Source: Arthur D. Little, Inc., 1978 Petrochemical Industry Profile
Petrochemical Energy Group, September 5. 1979
Petrochemical Salt?
to Other Induttritt
_>». $36.2 Billion
- A Report to the
Figure D-12. The U.S. Petrochemical Industry - 1978
-------
D-13 shows the flow of primary petrochemicals to the motor vehicle
industry, highlighting butadiene (raw material for rubber making) and
materials for paint, batteries, and synthetic fibers. During 1979, the
total U.S. production of the selected primary petrochemicals was 82.69
billion pounds as compared to 70.72 billion pounds produced in 1978
(Reference 22).
D.3.2 Major Petrochemicals
In this section, primary petrochemicals selected for this assessment
are discussed in terms of the feedstock sources from petroleum and natural
gas and U.S. gross production in 1979 and 1978. The regional breakdown of
the gross production for benzene in the U.S. is given by the EPA federal
regions. Also, the selected primary petrochemicals are discussed in terms
of the existing industry modes of transportation, storage, and distribution
systems. Because of the lack of data to properly assess ethylene,
propylene, toluene, xylene, and butadiene, only benzene is discussed as an
example petrochemical for transportation and storage systems and end uses.
D.3.2.1 Sources
Basically, petroleum and natural gas are the two primary sources of
petrochemicals produced in the U.S. today. However, some petrochemicals
(e.g., benzene) are made from coke-oven light oil, a by-product of steel
manufacturing. Petroleum is used as the primary feedstock material for the
selected primary petrochemicals discussed. Natural gas, on the other hand,
is used for the organic synthesis of ethylene. The synthesis gas is pro-
duced from ethane, which is the third step in the natural gas refining
process.
In the case of petroleum-derived petrochemicals, the raw materials
(crude oil) are used as feedstock at the petroleum refinery. These raw
materials are catalytically changed into several organic chemical com-
pounds. The types and quantities of petrochemicals produced are somewhat
dependent upon the particular catalytic process used and the desired end
products. Natural gas-derived petrochemicals are produced in a similar
manner. Providing that most natural gas transported to the refinery is
wet, i.e., contains natural gas liquids, the processing steps require
drying the gas, removing hydrogen sulfide, and liquefying the gas. In the
second step of natural gas processing, the basic alkane (i.e., ethane)
gases are produced. These are subsequently modified to produce
petrochemicals such as ethylene and propylene (Reference 23).
The U.S. gross production of the selected primary petrochemicals was
82.69 billion pounds during 1979 and 70.72 billion pounds during 1978.
This 1979 production is an annual increase of about 16 percent over the
1978 production. Table D-12 shows the U.S. production of the selected
petrochemicals ranked by the volume of production for 1978-1979. This
table shows that the average annual percent change in the primary petro-
chemical production varied and resulted in an increase of 0.85 percent for
butadiene and about 55 percent for toluene over 1978 production. Toluene
D-36
-------
TANA
L
COLORADO
I KANSAS \
I 1
WMEXICO- -£_._- ~ oVlAH
TEXAS ]
petrochemical
Feedrtock
Source: Arthur D. Little, Inc., The Petrochemical Industry and the U.S. Economy-
A Report to the Petrochemical Energy Group, December 1978.
Figure D-13. The Flow of Petrochemicals to the Motor Vehicles Industry
D-37
-------
had the largest annual percentage growth while butadiene had the smallest.
In 1978, the production of toluene declined 1.2 percent below the 1977
production. The increase of 55 percent growth in 1979 is attributed to
toluene's relatively new use as a blending agent to raise the octane rating
of unleaded gasoline as observed by industry (Reference 22).
Historically (1969-1979), the production statistics of the selected
primary petrochemicals show that the average annual percent change in
production varied and show an increase of 1.3 percent for butadiene and 9.9
percent for p-xylene during that period. These statistics also show that*
butadiene was the least produced while ethylene ranks as number one among
the selected primary petrochemicals produced during the ten-year period
(Reference 22).
Using these statistics as a basis, the future supply of feedstock
materials can be determined conservatively. It is anticipated that syn-
fuels derived from coal and oil shale will provide a small percentage of
feedstock materials for production of petrochemicals, because of our
reduced national supply of petroleum and natural gas and the concern for
how these natural resources should be used in the future as fuels and
feedstock materials (Reference 20).
TABLE D-12. UNITED STATES PRODUCTION OF SELECTED PETROCHEMICALS
RANKED BY VOLUME
1979 1978 1978-1979
Primary Production Production Average Annual Change
Petrochemicals (Billions of Ib) (Billions of Ib) (%)
Ethyl ene
P ropy 1 ene
Benzene
Tol uene
Xylene3
p-Xylene b
Butadiene (l,3)u
29.19
14.30
12.72
11.86
6.89
4.18
3.55
25.96
13.01
10.94
7.64
6.13
3.52
3.52
12.44
9.92
16.27
55.24
12.40
18.75
0.85
Total 82.69 70.72 125.87
a Include all grades
Rubber grade
Source: "C&EN's Top Fifty Chemical Products and Producers Special
Report", Chemical and Engineering News, May 5, 1980, pp. 33-37.
The regional disaggregation of the gross U.S. production of primary
petrochemicals produced during 1979 is based upon the quantities produced
by each state as reported in the Draft Environmental Impact Statement -
D-38
-------
Benzene Emissions from Benzene Storage Tanks, Background Information for
Proposed Standards, EPA-450/ 3-80-034a (Reference 24).This regional
breakdown is required to determine the types and quantities of petro-
chemicals transported, stored, and distributed throughout the U.S. The EPA
report, the only available data at this time, deals specifically with
benzene. Thus, using the data reported for the individual states, the
benzene production data by state was mapped to the ten EPA regions. The
results of this mapping process, shown in Table D-13, show that over 58
percent of the benzene produced in the U.S. during 1979 came from EPA
Region VI, which includes Louisiana, Texas, and Oklahoma. The second
highest producing region in the U.S. is Region II, which includes New
Jersey, New York, and the U.S. territories of Puerto Rico and the Virgin
Islands.
D.3.2.2 Transportation
The transportation network is a vital link in the transport,
distribution, and storage of petrochemicals. Transportation connects
producers and consumers, who are widely distributed throughout the U.S.
The purpose for assessing the transportation of these selected primary
petrochemicals is to gain an understanding of the existing transportation
network in order to eventually determine how synfuel-derived petrochemicals
will fit into the existing transportation infrasturcture. The data
required to completely assess the petrochemical network is not available in
the required format. (This data needs to be reported in the form of petro-
chemical types and quantities transported by states, federal regions, or
PADD's to make it consistent with the data presented for production.)
Thus, the transportation of the selected primary petrochemicals is
difficult to assess at this time.
Some transportation data was obtained from the Department of Commerce,
Bureau of Census, census of Transportation Department. This data shows
transportation of the selected primary petrochemicals as an aggregate with
crude products from coal and petroleum tars. The Census Bureau classifies
commodity transportation modes according to a 5-digit Standard
Transportation Commodity Classification (STCC) code that is similar to the
4-digit-level Standard Industrial Classification (SIC) code. The two codes
are not directly related.
The data obtained from the Census Bureau was abstracted by telephone
from the 1972 Census of Transportation Report from a staff member in the
transportation department (Reference 25). Tn this report, the selected
primary petrochemicals are aggregated into the STCC code 28141 - Crude
Products from Coal and Petroleum Tars. The U.S. total tons shipped for
this code by transportation mode and the percent transported by each mode
is presented in Table D-14. (It was cautioned that this data has a
standard error of 26 percent.) As noted in Table D-14, barge transporta-
tion accounted for 44.1 percent, rail-34.8 percent, motor carrier-20.2
D-39
-------
TABLE D-13. REGIONAL/STATE OR TERRITORY PRODUCTION OF BENZENE-1979
Region/State Capacity Percent of
or Territory (Billions of Ib) Total Capacity
New England (I)
New York/New Jersey (II)
New Jersey
New York
Puerto Rico
Virgin Islands
Subtotal
Middle Atlantic (III)
Maryland
Pennsylvania
Subtotal
Southeast (IV)
Kentucky
Subtotal
Great Lakes (V)
111 inois
Michigan
Ohio
Subtotal
South Central (VI)
Louisiana
Texas
Oklahoma
Subtotal
Central (VII)
Kansas
Subtotal
NA
0.223
0.146
1.876
0.413
2.658
0.095
0.846
0.941
0.407
0.407
0.394
0.191
0.331
0.916
1.635
5.660
0.153
7.448
0.083
0.083
NA
1.75
1.15
14.75
3.25
20.90
0.75
6.65
7.40
3.20
3.20
3.10
1.50
2.60
7.20
12.85
44.85
1.20
58.55
0.65
0.65
D-40
-------
TABLE D-13. (CONTINUED)
Region/State Capacity Percent of
or Territory (Billions of Ib) Total Capacity
Mountain (VIII)
Utah 0.025
Colorado 0.020
Subtotal 0.045 0.35
West (IX)
California
Subtotal
Northwest (X)
Total U.S.
0.222
0.222
NA
12.720
1.75
1.75
NA
100.00
NA Not available
Sources: "C&EN's Top Fifty Chemical Products and Producers Special
Report", Chemical and Engineering News. May 5, 1980, pp. 33-37.
Adapted from Environmental Protection Agency, Draft Environmental Impact
Statement - Benzene Emissions from Benzene Storage Tanks - Background
Information for Proposed Standards, EPA-450/3-80-034a. September. 1980
percent, and private truck-0.9 percent. Also, this data represents only
long-distance transport of materials versus local transport. Pipelines,
which were considered initially to be another mode of transportation, are
not included as part of the transportation network for STCC 28141
(Reference 25).
0.3.2.3 Benzene Storage
Benzene storage facilities are located throughout 19 states within the
continental U.S. There are 494 tanks in 143 facilities. There are three
types of facilities: (1) benezene producing facilities; (2) benzene con-
suming facilities; and (3) bulk storage terminals (Reference 24).
The greatest concentration of storage facilities is in Texas. Texas
contains 52 percent of the total combined production storage facilities, 36
percent of the total consumer storage facilities, and 75 percent of the
bulk storage facilities.
D-41
-------
Total U.S. benzene storage capacity is equal to 278 million gallons.
Of the 143 facilities that are known to store benzene, 54 (41 percent) are
benzene producers, 73 (56 percent) are benzene consumers, and 4 (3 percent)
are bulk storage terminals.
TABLE D-14. U.S. SHIPMENT OF CRUDE PRODUCTS FROM COAL AND PETROLEUM
TARS TOTAL TONS SHIPPED BY TRANSPORTATION MODE IN 1972
Percent Tonsa
Transportation Transported Transported
Mode By Mode By Mode
Barge
Rail
Motor Carrier
Private Truck
44.1
34.8
20.2
0.9
1,030,176
812,928
471,872
21,024
U.S. Total 100.0 2,336,000
aThis data represents total tons transported only long distance. Pipeline
transportation was not included. This data also has a standard error of
26 percent or 607,360 tons
Source: Personal communication with Robert Torene, Department of Commerce,
Bureaus of Census, Census of Transportation, September 8, 1980
D.3.3 Benzene End Use
Benzene currently is used almost exclusively as a feedstock material
in the production of other materials. The major benzene derivatives used
in producing other materials are: ethylbenzene-50 percent, cumene-15
percent, cyclohexane-15 percent, and aniline-5 percent (Reference 24).
Ethylbenzene is used in the production of styrene for polystyrene, and
cumene is used for phenol and for starting material for nylon
intermediates.
The regional consumption of benzene and its major derivatives is
constrained to seven federal regions consisting of ten states. These
states, in order of magnitude of consumption, are: Texas, Louisiana,
Michigan, Pennsylvania, Kentucky, Oklahoma, New Jersey, Kansas, niin°Js>
and California. (Note: the territory of Puerto Rico is excluded.) The
regional aggregates of these states include: Region II, New Jersey; Region
III Pennsylvania; Region IV, Kentucky; Region V, Michigan and Illinois;
Region VI, Texas, Louisiana and Oklahoma; Region VII, Kansas; and Region
IX, California. However, not all derivatives are produced in all states.
Refer to Table D-15 for a more detailed representation.
D-42
-------
TABLE D-15. BENZENE CONSUMPTION IN THE U.S. BY EPA REGION 1979
Region/State or Territory
New York/Mew Jersey-II
Puerto Rico
New Jersey
Middle Atlantic-II
Pennsylvania
Southeast-IV
Kentucky
Great Lakes-V
111 inois
Michigan
South Central -VI
Louisiana
Texas
Oklahoma
Central -VI I
Kansas
West-IX
TOTAL U.S.
Consumption
2.47^
0.27b
2.74
0.73b
0.68&
0.2lb
1.17C
1.38
7.04C
20.11d
0.48e
27.63
0.26b
0.20b
33.62
Quantities in MMBBL
% of Consumption % of
7.35
0.81
8.16
2.17
2.01
0.64
3.49
4.13
20.93
59.83
1.42
82.18
0.78
0.58
100.01
Production
5.97
0.66
6.63
1.76
1.64
0.52
2.84
3.36
17.00
48.59
1.15
66.14
0.63
0.49
81.25f
NOTE:
acyclohexane 1.23, and cumene 1.24 production.
cumene production.
cethyl benzene and styrene production.
dethyl benzene and styrene 11.8, cyclohexane 4.83, and cumene 3.48
production
ecyclohexane production.
total benzene production 41.38 million barrels.
t
Sources: Adapted from "C&EN's Top Fifty Chemical Products and Producers
Special Report", Chemical and Engineering News, Hay 5,
1980, pp. 33-37.
Adapted from Environmental Protection Agency, Draft Environmental
Impact Statement --Benzene Emissions From Benzene Storage Tanks~-
Backqround Information for Proposed Standards,
EPA-450/3-80-034SUD16a, September, 1980.
D-43
-------
TABLE D-16. U.S. CONSUMPTION OF BENZENE AND ITS MAJOR DERIVATIVES
BY SELECTED EPA REGIONS
(QUANTITY IN MMBBL)
Benzene
Consuming
Products
Ethyl benzene/
Styrene
Cyclohexane
Cumene
Total Benzene
Region III
Middle
Atlantic
0.73
0.73
Region IV Region V
Southeast Great Lakes
1.17
0.68 0.21
0.68 1.38
Region VI Region VIII
South Mountain
Central
18.84
5.31
3.48
27.63
Sources: Adapted from "C&EN's Top Fifty Chemical Products and Producers
Special Report", Chemical and Engineering News, May 5, 1980, pp. 33-37.
Adapted from Environmental Protection Agency, Draft Environmental Impact
Statement—Benzene Emissions from Benzene Storage Tanks - Background
Information for Proposed Standards, EPA-45Q/3-80-034a, September 1980.
The major derivatives of benzene eventually yield end products that
can be classified. The major end products are: polystyrene-25 percent,
other styrene resins-10 percent, nylons-20 percent, and styrene-butadiene
rubber-5 percent (Reference 25). About 25 percent of these products are
ultimately used in consumer goods such as packaging, toys, sporting goods,
disposables, novelties, and other small manufactured items (Reference 24).
Another 17 percent of benzene derivatives, especially nylon fibers and
resins, are used in the manufacture of household goods such as furniture,
appliances, and carpeting (Reference 25). The transportation industry
accounts for another 17 percent of benzene derivative consumption
(Reference 25). Plastics, fibers, elastomers, and rubber are used in the
production of boats, trucks, automobiles, and airplanes.
In characterizing the current regional consumption patterns, Table
D-16 shows that Regions V and VI are the largest consumers of benzene and
its major derivatives. These regions together consumed about 86 percent of
the total benzene consumed in 1979, corresponding to about 70 percent of
the total production. The remaining 14 percent was consumed in Regions II,
III, IV, VII, and IX.
It is worthy to note that no consumption of benzene occurred in Region
VIII; however, this region produces benzene, about 0.15 MMBBL (0.35 billion
Ib), as shown in Table D-13. Table D-16 shows the current consumption
patterns for benzene and its major derivatives in the U.S. for 1979 by
selected EPA regions. This table applies only to the selected five regions
of synfuels production (see Section 3.1) chosen as likely locations of
synfuels plants. Thus, Regions, II, VII, and IX are omitted.
D-44
-------
D.4 SOURCES OF POLLUTANT EMISSIONS TO THE ENVIRONMENT FROM CONVENTIONAL
FUELS TRANSPORT AND STORAGE
Synfuels products and by-products will be released into the
environment during transportation, storage, and utilization in much the
same manner as currently used fuels are. The existing conventional fuel
and petroleum product distribution system is expected to be used, and the
major end uses of the synfuel products are expected to be the same as for
these products' petroleum-based counterparts. The existing distribution
system is not expected to be significantly affected by any of the three
scenarios for product buildup rates, although modifications may be
necessary. The major sources of synfuels emissions to air, water, or land
are through normal handling and end use operations, as well as accidental
releases resulting from leaks and spills. Petroleum product storage and
transportation accounts for approximately 4 percent of the nationwide
volatile organic compound emissions and negligible amounts of the other
criteria pollutants (Reference 27). Each of the sources of emissions is
described in the following sections.
D.4.1 Transportation Modes Used for Conventional Fuels
Because synfuels products will be transported by several modes, as
conventional fuels are now, the relative safety of each of these modes
needs to be assessed to determine the potential exposure from predictable
accidental release of products. Each of the transportation modes has
inherent risks from accidents, as described in the following sections.
Table D-17 presents hdyrocarbon emission factors for petroleum liquid
transport operations. Products with the highest vapor pressures have the
highest rate of emissions, which also should be considered in the analysis
of various synfuels products (Reference 28).
D.4.1.1 Pipelines
Pipelines currently transport over 72 percent and 36 percent of the
crude and refined petroleum products respectively, and virtually all of the
natural gas in the U.S. This mode offers the most economical and generally
the safest method for long-distance transport of liquid products. Although
pipeline systems have good safety records, the economies of scale that make
pipelines feasible also create a potential for large accidental releases of
products, because the ability to detect a release and isolate the release
point is limited. Environmental impacts from normal pipeline operations
are very low, producing atmospheric emissions during venting. The other
source is accidental release, primarily caused by pipeline rupture.
During 1979, a total of 1,970 gas pipeline and 251 liquid pipeline
accidents occurred (Reference 29). Because more liquid than gaseous
synfuel products will use pipelines, emphasis is placed on the former.
Existing pipelines will be used for the most part under both the national
goal and nominal production rate scenarios, with new pipelines connecting
to existing trucklines. Additional pipelines may be needed for the
D-45
-------
TABLE D-17.
HYDROCARBON EMISSIOfl FACTORS FOR PETROLEUM LIQUID
TRANSPORTATION SOURCES (LB 103 GALLOfIS TRANSFERRED)
o
i
Source Gasoline
RAILROAD TANK CARS/TRUCKS
Submerged Loading
Normal Service 5
Balance Service 8
Splash Loading
Normal Service 12
Balance Service 1
Transit - Typical (Loaded) 0-0.1
- Extreme (Loaded) 0-0.8
- Typical (Empty) 0 - 0.11
- Extreme (Empty) 0 - 0.37
MARINE VESSELS
Tanker Loading 1-2.4
Barge Loading 1.3 - 3.3
Tanker Ballasting 0.8
Transit 3
Product Emission Factors
Crude Jet Jet
Oil Naphtha Kerosene
3
5
7
0.6
b
t
b
b
0.7
1.7
0.6
1
1.5
2.5
4
0.3
b
b
b
b
0.5
1.2
b
0.7
0.02
a
0.04
a
b
b
b
b
0.005
0.0013
b
0.005
No. 2
Fuel Oil
0.01
a
0.03
a
b
b
b
b
0.005
0.012
b
0.005
No. 6
Fuel Oil
0.0001
a
0.0003
a
b
b
b
b
0.00004
0.00009
b
0.00003
-------
accelerated rate scenario, as a production rate of approximately 2.5 MMBPD
of coal liquids is projected by the late 1990s. Although refined products
would use existing pipelines, transporting coal liquids between the lique-
faction plants and major terminals may necessitate new pipelines. Crude
shale oil pipelines would also be needed to feed into existing pipelines to
refineries in Colorado, the Rocky Mountain area, the Gulf Coast, or the
Midwest. The crude shale oil pipelines would be required under all three
scenarios by the late 1980's to handle a production rate of 0.2 to 0.5
WBPD.
Based on a nine-year history of pipeline accidents, most accidents
occur in crude oil pipelines, which in 1979 accounted for over 50 percent
of the accidents (Ref. 30). Pipelines carrying gasoline, fuel oil, and LPG
comprised almost 40 per cent of the total. The remainder of the accidents
occurred in pipelines carrying various other products as shown in Table
D-18. The causes of pipeline accidents vary with the greatest number
occurring from ruptures in the pipe. Internal corrosion was responsible
for less than 5 percent of the accidents. Because the corrosive properties
of synfuels are unknown at this time, an accurate assessment of the
potential for increased accidents from corrosion cannot be made.
As previously mentioned, the potential for accidental release of large
amounts of products is high, even though the transportation system is
relatively safe. In one pipeline accident near Devers, Texas in 1975, a
single pipeline accident released more than 600,000 gallons of natural gas
liquids. Although the fate of all the products on Table D-18 is unknown,
damage losses were assessed because the products were emitted into water or
soil and could not be recovered. During 1978, approximately 10 percent of
all petroleum products spilled into waterways was from pipelines (Reference
31). LPG accounted for the greatest amount of product lost (approximately
59 percent), although LPG pipelines were involved in only 13.5 percent of
the accidents. Many of these conventional products will have synfuel
counterparts that will have the same accident potential. During the last
nine years, pipeline accidents decreased slightly. This trend should
continue as pipeline construction and operating standards become more
stringent, making both conventional fuels and synfuel product transport
safer.
Another factor to be considered in transporting synfuels by pipeline
is the location of potential accidents. The state of Texas has consis-
tently had the highest number of accidents since reporting records have
been kept. However, this is more a function of the amount of pipeline in
the state than a reflection of poor operation. The states with the highest
incidence of pipeline accidents, accounting for 60 percent of the total,
are in addition to Texas, Oklahoma, Kansas, Illinois, Wyoming, and
Louisiana. All of these areas are expected to be involved in synfuel
production or end use.
M.1.2 Water Carriers
Waterborne transport accounts for approximately 13 and 25 percent of
-he crude and refined petroleum products transport, respectively. The
D-47
-------
TABLE D-18. LIQUID PIPELINE ACCIDENT SUMMARY - 1979
o
oo
Commodi ty
Crude Oil
Anhydrous Ammonia
Jet Fuel
Gasoline
Oil and Gasoline
Turbine Fuel
Diesel Fuel
Fuel Oil
Condensate
LPG
NGL
No. of Accidents
132
1
5
38
6
1
6
22
1
34
5
(%)
52.2
0.4
2.0
15.1
2.4
0.4
2.4
8.8
0.4
13.5
2.0
Loss of Product
(Barrels)
138,163
3,425
3,333
25,411
1,922
150
5,397
34,237
584
321 ,446
14,601
Percent of
all Losses
25.2
0.6
0.6
4.6
0.4
0.0
1.0
6.2
0.1
58.6
2.7
TOTAL
251
99.6
548,669
100.0
-------
major operational source of air and water pollutants are from tanker and
barge loading and unloading and from ballasting. Most air pollution
emissions consist of volatile organic compounds from gasoline handling,
because of its higher vapor pressure than middle distillates.
Water transport is used in inland and ocean waterways as well as in
the Great Lakes region. The largest amounts of oil discharges during 1978
occurred in river channels on the Atlantic seaboard, and accounted for
about 43 percent of the oil spilled during 1978 (Reference 31). The second
highest area is the Gulf Coast, accounting for approximately 14 percent.
The largest quantity of products discharged were fuel oil, followed by
crude oil, gasoline, and diesel oil. These products all entered local
waters, contributing to potential water pollution impacts on aquatic life
and human health.
The major sources of oil spills from water transport are bulk transfer
of products at marine facilities and leaks from vessels. Hull and tank
rupture or other structural failures are responsible for more than 70
percent of the accidents, while improper operation by personnel was
responsible for only one percent.
By location, in 1978 the largest spills were in New Jersey, although
the greatest number of accidents occurred in Louisiana. Other states with
significant oil spills were Massachusetts, Delaware, and Rhode Island.
D.4.1.3 Tanker Trucks
Tanker trucks transport approximately 14 percent of the crude oil and
36 percent of the refined product in the United States. Because of their
mobility, trucks will also be used in synfuels transport, unless their
operating costs reduce their competitiveness. Tank truck emissions occur
during truck loading at storage terminals and unloading at service
stations. Trucks are also used for transporting packaged petroleum
products such as lubricating oils, grease, and wax, which have little
contact with personnel handling the products and do not release pollutants
during transport. The most volatile product transported by trucks is
gasoline, which releases organic vapors during unloading into service
station storage tanks. The gasoline is either splashloaded or submerged-
filled, with the latter method more frequently used due to volatile organic
compound emission control requirements mandated by state implementation
plans for those areas not meeting air quality standards for ozone.
The potential for accidental release of hazardous materials
transported by trucks is related to the accident rate of all highway
vehicles to which freight trucks are exposed, regardless of the commodity
carried. Of the more than 11,000 incidents involving hazardous materials
in transport, only 6 percent involved petroleum products (gasoline),
although gasoline accounted for the largest amount of products lost during
1978. Highway vehicles were responsible for spills of 400,000 gallons of
oil and 19,000 gallons of chemical compounds into waterways, accounting for
only 2.8 percent and 0.9 percent respectively of the total amount of
products entering waterways from all sources.
D-49
-------
D.4.1.4 Railroads
Railroads carry the least amount of crude oil and refined petroleum
products, accounting for 0.33 percent and 1.8 percent, respectively, during
1977. Railroads transport considerably higher quantities of petrochemicals
and liquefied petroleum gases used as feedstocks between chemical plants.
Pollutant releases consist primarily of organic compound vapors emitted
during product loading, unloading, and transit operations as well as
accidents when high pressure tank cars are ruptured. Accidental releases
can also enter waterways, depending upon whether the products volatilize or
remain liquid. Railroad safety has emerged as a major concern of govern-
ment and railroad officials because of the resurgence of railroads as a
means of transporting freight and passengers. Shipments of coal within the
U.S., as well as to terminals for subsequent transport to overseas
markets, is responsible for part of the industry's growth. It is expected
that fuels and petrochemical transport will increase to take advantage of
existing rail networks that can be used to serve synfuels markets. The
condition of the nation's railroads, specifically the tracks, are of
concern because more than 77 percent of the 11,000 accidents were caused by
derailments. There were 1,035 accidents involving hazardous materials that
required evacuation of more than 26,000 people in various states (Reference
32). The highest number of train accidents occurred in Illinois, while
Texas had the greatest number of accidents involving hazardous materials.
Both of these areas will experience market penetration by synfuels, and
railroads are expected to be used to transport heavy coal liquids to
utility and industrial plants as well as to refineries for blending.
Water pollution caused by railroad accidents provides a potential for
contamination only when products are spilled over or near receiving water.
In 1978, 0.6 percent of the oil and 3.5 percent of the hazardous substances
entering waterways was due to railroad accidents.
D.4.2 Product Storage
The storage of crude oil and refined petroleum products contributes a
very small amount to the nation's air and water pollution. Approximately
three percent of the nationwide volatile organic compound emissions to the
atmosphere are from petroleum storage. There are virtually no air pollu-
tants released from natural gas storage. Petroleum products are stored at
refineries, marketing terminals, tank farms, and major end users' facili-
ties, such as utility plants and airports. Emissions from storage tanks
occur from breathing losses around tank seals and working losses from tank
filling and unloading. Products having major pressures ranging from 1.52
to 9.1 psia account for the greatest amount of emissions, with gasoline
accounting for over 50 percent (Reference 33). Crude oil storage accounts
for 17 percent of the emissions. Synfuel product emissions will also
depend on vapor pressures and, based on prelimnary information, are for the
most part equivalent to emissions from petroleum products.
D-50
-------
During 1977, leaks and spills from storage facilities accounted for
15,780 barrels of oil or 4.7 percent of all oil products entering U.S.
waterways from accidents or incidents. Storage of hazardous materials
accounted for 0.1 percent of all hazardous materials spilled into water-
ways. Waste waters associated with crude oil and product storage are
mainly in the form of emulsified oil and suspended solids. During storage,
the water and suspended solids in the crude oil separate, forming a bottom
sludge below the oil layer. As the water layer is drawn off, emulsified
oil is often lost to the sewer system and is high in chemical oxygen
demand. Intermediate storage is frequently the source of polysulfide and
iron sulfide suspended solids. Finished product storage can produce high
biochemical oxygen demand and alkaline waste waters. The properties of
synfuel products will need to be characterized to assess this after
products are drawn off from the tanks. Tetraethyl lead used as an anti-
knock compound and having toxic properties can also contribute to waste
steams; however, the amount of this compound is decreasing because of the
requirements for unleaded gas. Tank cleaning can contribute large amounts
of oils, COD, and suspended solids from petroleum products and may do the
same with synfuels, depending upon their constituents.
As crude oil storage tanks are being modernized, waste waters will be
reduced because of the use of mixed crude storage tanks and strict
specifications on bottom sediment and water. The increased use of drying
processes preceding product finishing can significantly reduce the water
content of the product, thereby minimizing the quantity of waste water from
finished product storage. This will be of benefit not only to storage of
petroleum products but to synfuels as well if the latter products are
similar in composition to petroleum.
REFERENCES
1. Energy Information Administration, Annual Report to Congress,
Volume I, 1979.
2. Congressional Research Service, National Energy Transportation
Volume I - Current Systems and Movements, May 1977.
3. Association of Oil Pipelines, Shifts in Petroleum Transportation,
1977.
4. Energy Information Administration, Energy Data Reports, Petroleum
Refineries, Annual, January 1, 1978.
5. National Petroleum Council, Petroleum Storage and Transportation
Capacities - Pipelines, Volume III, December 1979.
6. National Petroleum Council, Petroleum Storage and Transportation
Capacities - Executive Summary, Volume I, December 1979.
D-51
-------
7. U.S. Department of Energy, Petroleum Supply Alternatives for the
Northern Tier and Inland States Through the Year 2000. Vol. 1
October 31, 1979.
8. Energy Information Administration, Energy Data Reports, Petroleum
Statement, Monthly, November 1979. ~~
9. National Petroleum Council, Petroleum Storage and Transportation
Capacities - Waterborne Transportation. Volume V, December 1979.
10. National Petroleum Council, Petroleum Storage and Transportation
Capacities - Tank Cars/Trucks. Volume IV, December 1979.
11. Energy Information Administration, Energy Data Reports. Petroleum
Statement. Annual, 1978. ~
12. National Petroleum Council, Petroleum Storage and Transportation
Capacities - Inventory and Storage, Volume II, December 1979.
13. Energy Information Administration, State Energy Data Report.
April 1980.
14. National Petroleum Council, Petroleum Storage and Transportation
Capacities - Gas Pipeline, Volume VI, December 1979.
15. Adapted from Monthly Energy Review, EIA, U.S. DOE, February 1980.
16. Energy Source Book, The Center for Compliance Information, 1977,
t
ibe
18. The Condensed Chemical Dictionary, 9th Edition, 1977, p. 664.
17. Arthur D. Little, Inc., 1978 Petrochemical Industry Profile -
A Report to the Petrochemical Energy Group, September 5, 1979
19. Dictionary of Scientific and Technical Terms, 2nd Edition, 1978
McGraw-Hill.
20. "Allocation Rules Could Hurt Petrochemicals". Chemical and
Engineering News Journal, June 2, 1980, page 5.
21. Arthur D. Little, Inc., The Petrochemical Industry and the U.SA
Economy—A Report to the Petrochemical Energy Group, December,
1978.
22. "C&EN's Top Fifty Chemical Products and Producers Special
Report", Chemical and Engineering News . May 5, 1980, pp. 33-37.
23. Stanford Research Institute, Chemical Origins and Markets—-
Product Flow Charts Tables of Major Organics and Inorganics,
cFemical Information Services, Menlo Park, California, 1967.
-------
24. Environmental Protection Agency, Draft Environmental Impact
Statement—Benzene Emissions from Benzene Storage Tanks,
Background Information for Proposed Standards, EPA-450/3-80-034a,
September, 1980.
25. Personal Communication with Robert Torene, Department of
Commerce, Bureau of Census, Census of Transportation, September
8, 1980.
26. Standard & Poor's Industry Survey, 1980.
27. National Air Data Branch, U.S. Environmental Protection Agency,
1977 National Emissions Report, EPA-450/4-80-005, March 1980.
28. National Air Data Branch, U.S. Environmental Protection Agency,
Compilation of Air Pollutant Emission Factor: AP-42, through
supplement 10, February 1980.
29. Transportation System Center, U.S. Department of Transportation,
Transportation Safety Information Report, May 1980.
30. Materials Transportation Bureau, U.S. Department of
Transportation, Pipeline Accident Summary, June 1980.
31. U.S. Coast Guard, Polluting Incidents In and Around U.S. Waters,
Calendar Years 1977 and 1978, January 1980.
32. Federal Railroad Administration, Accident/Incident Bulletin No.
147, Calendar Year 1978, October 19/9.
33. U.S. Environmental Protection Agency, Evaluation of Hydrocarbon
Emissions from Petroleum Liquid Storage, EPA-450/3-78-012, March
1978.
D-53
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E.I
E.2
E.3
E.4
APPENDIX E
PHYSICAL AND CHEMICAL
CHARACTERIZATION OF SYNFUEL PRODUCTS
TABLE OF CONTENTS
PHYSICAL AND CHEMICAL CHARACTERIZATION OF SHALE
OIL PRODUCTS
1,
.1,
1,
1,
E.I.5
Crude
Shale
Shale
Shale
Shale
Shale Oil .
Oil Derived
Oil Derived
Oil Derived
Oil Derived
Gasoline Stocks . ,
JP-5 ,
Diesel Fuel Marine
Residual Fuels. . .
(DFM)
PHYSICAL AND CHEMICAL CHARACTERIZATION OF DIRECT
LIQUEFACTION LIQUIDS (SRC-II, H-COAL AND EDS). .
E-4
E-4
E-9
E-9
E-14
E-14
E-14
E.2.1 Direct Liquefaction Oils E-14
E.2.2 Direct Liquefaction Naphtha E-18
E.2.3 Gasoline from Direct Liquefaction Processes E-18
E.2.4 No. 2 Fuel Oil from Direct Liquefaction . . E-26
E.2.5 Jet and Diesel Fuels from Direct
Liquefaction E-26
CHEMICAL CHARACTERIZATION OF INDIRECT LIQUIDS.
3.1 Fischer-Tropsch Gasoline
E.3.1.1 F-T By-Product Chemicals Composition
E.3.1.2 Tars, Oils and Phenols
Mobil-M Gasoline
Methanol
E.3.2
E.3.3
E-26
E-26
E-31
E-31
E-36
E-36
CHEMICAL CHARACTERIZATION OF COAL GASES E-38
E.4.1 SNG E-38
E.4.2 Chemical Characterization of Low-/Medium-
BTU Coal Gas . . E-33
E-l
-------
TABLES
Page
Table E-l Shale Oil and Petroleum Crude Physical Data
Comparison .................... E-5
Table E-2 Shale Oil and Petroleum Crudes Chemical Data ... E-7
Table E-3 Range of Trace Elements from Oil Shale and
Petroleum Crudes (PPM) .............. E-8
Table E-4 Chemical Characterization of Heavy Distillates
Shale Oil and Petro Crude ............. £-10
Table E-5 Shale Oil Gasoline Stocks Analyses ....... E-ll
Table E-6 Inspections of Hydrotreated and Reformed Gasoline
from Pilot Plant Studies of Shale Oil Upgrading. . E-12
Table E-7 Shale Oil JP-5 Analyses ............. E-13
Table E-8 Shale Oil DFM Analyses ............. E-15
Table E-9 Shale Oil Residual Fuel Analyses ......... E-16
Table E-10 Physical Properties of SRC II, H-Coal and EDS
Raw Process Liquids ................ E-17
Table E-ll Chemical Composition of SRC II, H-Coal and EDS
Raw Process Liquids ................ E-19
Table E-12 Physical Properties of Coal Derived Naphtha. . . . E-20
Table E-13 Detailed Chemical Analysis of SRC II, EDS, and
H-Coal Naphthas .................. E-21
Table E-14 Detailed Chemical Analysis of SRC II, EDS, and
H-Coal Hydrotreated Naphthas ........... E-22
Table E-15 Physical Properties of Gasoline Produced from
Differenct Syncrude Feedstocks ........ E-23
Table E-16 Comparison of Coal Derived Gasoline Composition. . E-2-
Taole E-17 Gasoline Comparison Specifications, Petroleum,
and Coal-Derived ................. E-25
Table E-18 Properties of No. 2 Fuel Oil Refined from
Petroleun and Syncrude .............. E-27
E-2
-------
Table E-19 Physical Properties of Jet/Diesel Fuels from
Coal Syncrude E-28
Table E-20 Detailed Specification for Jet Fuel, and
Diesel Fuel E-29
Table E-21 Comparison of Principal Unleaded Gasoline
Specifications with Estimated Fischer-Tropsch
Gasoline Properties Case II E-30
Table E-22 By-Product Chemicals Produced by Fischer-Tropsch
Synthesis E-32
Table E-23 Composition of Benzene Soluble Tars Produced in
Synthane Gasification Process E-33
Table E-24 Composition of Tars and Oils Produced by
Gasification of Various Coals in Lurgi Gasifiers . E-34
Table E-25 Organic Composition of Lurgi Oil Produced at
the Westfield Lurgi Facility E-35
Table E-26 Estimated Composition of Phenol By-Product Stream. E-31
Table E-27 Typical Properties of Finished Mob'il Gasoline. . . E-37
Table E-28 Estimated Crude Methanol Composition E-37
Table E-29 Typical SNG Composition (Dry) E-38
Table E-30 Gaseous Species Analysis Summary: Low-Btu
Coal Gas E-40
Table E-31 Trace and Minor Element Compositions of Low-Btu
Product Gas E-41
Table E-32 Organic Compounds Identified from the Product
Gas by SIM GC/MS E-43
E-3
-------
This appendix presents available data on the physical and chemical
characteristics of products from shale oil, direct and indirect coal
liquefaction, and coal gasification.
E.I PHYSICAL AND CHEMICAL CHARACTERIZATION OF SHALE OIL PRODUCTS
As part of DOD's synthetic fuel development program, 10,000 barrels of
shale oil crude were produced at Anvil Points, Colorado, by the Paraho
process (direct heat retort). The crude was refined into synthetic
gasoline, JP-4, JP-5, diesel fuel marine, and heavy fuel oil at the Gary
Western refinery in 1976. The fuels were shipped to numerous military and
private laboratories for specification tests, post-processing studies,
combustor tests, engine tests, burner tests, and full-scale tests.
This program was expanded in 1977 when the Standard Oil Company of
Ohio (SOHIO) was contracted by the U.S. Navy to refine up to 100,000
barrels of crude Paraho shale oil into military transportation fuels. The
objective of the program was to demonstrate that conventional refining
technology could be used to convert shale oil into stable, specification
military fuels in sufficient volume to support an extensive engine testing
program. Yields of JP-5 and diesel fuel marine (DFM) were to be maximized
while minimizing the yield of residual fuel.
The crude shale was produced by Paraho Development Corporation over
the three year period from 1976 to 1978. The crude shale oil was refined
by Sohio's Toledo refinery in late 1978.
As a result of these programs, reasonably large amounts of data exist
on the gross chemical and physical characteristics of crude shale oil and
its products. Much of the work on the initial 10,000 barrel run has been
completed. The testing of the 100,000 barrel run is in progress and only
limited data are available. In some cases, the assessment of the
differences between synfuel and petroleum products is limited because of
the scarcity of comparable data on petroleum products.
The following comparisons use actual petroleum product data where
available or ASTM or military specifications where no data were developed.
Comparison to ASTM or military specifications eliminates the problem of
selecting one representative petroleum product from the many that exist.
E.I.I CRUDE SHALE OIL
Table E-l compares nine crude shale oil samples to four petroleum
crudes of varying API gravity. The RO-1 to RO-4 shale oil samples were
from a blind API test program. The sources of those crude shale oils were
either the Union B, Paraho Direct, Paraho Indirect or Colony Semiworks.
Because of its unique nature, crude shale oil requires special
consideration in handling and processing. Compared to conventional
petroleum, shale oil has several deleterious characteristics (Reference 1):
E-4
-------
TABLE E-1. SHALE OIL AND PETROLEUM CRUDE PHYSICAL DATA COMPARISON
m
i
en
PHYSICAL PROPERTIES
Density (ASTMD-148-1)
at 153°F
Specific gravity @60°F
Viscosity (ASTM D-445)
SUS, 100 F
Viscosity, SUS, 130°F
Viscosity, (ATSM D-445),
SUS, 210°F
Pour Point (ASTM D-97), °F
Molecular weight (cryoscoplc)
Gravity, °API
DISTILLATION, VOLUME X
C, - 200°F
200 - 240
340 - 470
470 - 650
650+
IBP to 400°F
400 to 650
650 to 850
850+
IBP to 310°F
310 to 375
375 to 520
520 to 680
680 to 960
960+
(a)
IBP to 212 °F
212 to 302
302 to '(55
455 to 650
650 to 1049
1049+
CRUDE SHALE OIL5
0.9323
-
174.2
-
42.3
+85
274
-
6.07
27.99
25.33
39.66
RO-2<2>
0.9277
-
125.7
-
39.4
+80
265
-
7.20
30.17
34.31
27.66
RO-3<2>
0.9254
-
131.6
-
40.2
+65
272
-
9.91
25.87
28.92
34.63
RO-4
0.9393
-
107.2
-
38.1
+70
230
-
17.30
25.96
19.43
35.87
PARAHO /,
0 . SHALE*
_
0.9315
213
-
44.9
+85
-
20.4
DOW (3)
Tosor '
_
-
-
85.7
-
+75
-
20.7
5.2
4.54
12.64
30.85
32.57
26.84
PARAHO '
_
-
-
121.4
-
+85
-
20. i
1.17
1. 13
9.60
28.92
37.81
30.97
SUPERIOR(3)
TOSCO
.
-
-
105.5
-
+80
-
20.7
5.08
4.58
10.87
27.37
31.93
ji.04
OCCl-(3
DENTAL
'TOSCO
.
-
-
92 7
-
+50
-
19.3
6.30
4.53
13.64
33.07
31.73
24.37
P.FTRO FUM CFtUDFS , , . -
J. TEXASC
SOUR
CRUDE
.
-
43.1
-
-
-30
-
34.1
ARAB LA If*)
LIGHT
SAUDI
ARABIA
.
0.8545
-
-
-JO
-
33.4
9.0
8.4
15.0
19. 8
32.5
13.6
ARABIA^
HEAVY
SAUDL
ARABIA
-30
28.2
7.9
6.8
12.5
16.4
26. J
26.8
INDONESIA
1844
+ 57
20.6
i.5
i.7
4.9
12.9
78.9
-------
(!) High nitrogen and oxygen content
(2) Low hydrogen/carbon ratio
(3) Low yield of 650 F minus material (30 vol.%)
(4) Moderate arsenic and iron content
(5) Suspended ash and water.
The high nitrogen content is probably the greatest concern, as it is
an order of magnitude higher than that found in petroleum.
Nitrogen compounds are known to poison many petroleum processing
catalysts, such as those used in fluid bed catalytic cracking, naphtha
reforming, and hydrocracking. In addition, nitrogen compounds have been
found to create stability problems in gasoline, jet, and diesel fuels.
Fuel-bound nitrogen will also increase the NO emissions from practically
any type of combustor. Finally, nitrogen compounds often have a peculiar
and offensive odor that is difficult to remove.
The crude shale oils have consistently higher pour points than the
petroleum crudes, including the heavy crude from Indonesia. The specific
density of crude shale oil is generally higher than petroleum crudes.
These facts are supported by the distillation data, which show greater
volume percentages in the higher boiling fractions. Roughly 60 percent or
higher of the crude shale boils above 650 F compared to 40 to 50 percent
for two of the four crudes shown in Table E-l. Surprisingly, crude shale
oil is much less viscous than the heavy Indonesia crude even though the API
gravities are similar. This is probably because of the high aromatic
content of the crude shale oil.
Table E-2 displays the elemental analysis of the crude oils shown in
Table E-l. Only sulfur and nitrogen data were available for most of the
petroleum crudes. The sulfur values for the shale oils are compatible with
the normal range of sulfur values for petroleum crudes. As noted earlier,
the nitrogen content of crude shale oils greatly exceeds that of most
petroleum crudes. The nitrogen is generally believed to exist as
heteroatoms in ring compounds. Fortunately, mild hydrotreating can reduce
the nitrogen content to acceptable levels.
Some trace element (As, Na, K, V, Ni, Fe) data for shale oil and
petroleum crudes are also contained in Table E-2. More extensive data from
additional shale oil and petroleum crudes and their products is found in
Table E-3. In crude shale oil, only the elements As, Fe, and Th are
present in quantities that exceed the amounts present in petroleum crude by
an order of magnitude, as shown in Table E-3. Most of the elements are
present in the same order of magnitude or less than in petroleum crudes.
It is noteworthy that the vanadium content of shale oils is 100 times less
than typical petroleum levels. This finding could have a significant
effect on the sulfate emissions from the combustion of crude shale oil.
The lower vanadium content of crude shale oil will probably lead to less
HpSO, formation, because of vanadium's catalytic properties. The arsenic,
as weh 1 as most of the other elements, is readily removed during
hydrotreatment (Columns 6 & 7).
E-6
-------
TABLE E-2. SHALE OIL AND PETROLEUM CRUDES CHEMICAL DATA
Chemical Properties
ELEMENTAL ANALYSIS
Carbon, Wt %
Hydrogen
Oxygen
Sulfur
Nitrogen
METALS, PPM
As
Na
K
V
Ni
Fe
R0-l('2
85.6
11.6
1.2
0.68
2.17
33
2.1
-
0.12
2.0
40
RO-2^2
85.1
11.5
1.2
0.69
2.04
42
2.5
-
0.10
1.3
46
RO-3«
85.4
11.6
1.1
0.81
1.82
47
2.9
-
0.54
1.3
4.9
RO-4^
85.1
11.0
1.1
0.80
2.05
55
3.1
-
0.55
2.4
43
i>>—
•=»-
>»-'
> to
fO •!-
Qj _Q
*T* (O
t-
C e£
•t— »^
(O 3
S- to
<: co
-
-
-
2.84
-
_
-
-
-
-
*^*H
CO
•-— *
fO
»r.
-------
TABLE E-3. RANGE OF TRACE ELEMENTS FROM OIL SHALE AND PETROLEUM CRUDES (PPM)
ELEMENTS
A1
Ag
As
B
Ba
Be
Ca
Cd
Co
Cr
Cu
F
Fe
Hg
Mg
Mn
Mo
Na
N1
Pb
Sb
Se
S1
Sn
Sr
Th
T1
V
Zn
Zr
S
011 Shale(7)
Reference
0.1 - 36
5 - 65
3 - 7
0.01 - 21
0.02
0.5 - 39
0.01 - 0.2
0.8 - 7
0.04 - 0.2
0.1 - 1.5
0.1 - 3
6 - 390
0.09 - 0.65
0.4 - 100
0.1 - 4
5 - 14
19
1.1 - 5.5
0.02 - 7.8
0.008 - 0.54
0.08 - 0.2
110
1 - 36
0.3 - 60
0.075 - 3
0.1
(2)
RO-1
0.5
<0.02
33
<0.02
2
<0.02
0.82
0.02
0.08
40
<3
1.04
0.11
0.03
2.1
2.0
0.05
<2
<2
1
0.2
0.013
2
<1
0.12
0.61
(2)
RO-2
2
<0.02
42
<0.02
11
<0.02
0.52
0.05
0.05
46
<3
3.7
0.46
0.02
2.5
1.25
0.20
<2
<2
5
0.2
0.07
2
1
0.10
0.79
(2]
RO-3
2
<0.02
47
<0.02
5
<0.02
0.10
0.06
0.08
4.9
<3
1.7
0.67
0.05
2.9
1.26
0.17
<2
<2
3
0.4
0.03
1.5
<1
0.54
1.9
(2!
RO-4
4
<0.02
55
<0.02
37
<0.02
0.60
0.07
0.28
43
<3
7.4
0.22
0.06
3.1
2.4
0.09
<2
<2
9
0.4
0.27
<1
3
0.55
1.1
(a;
Crude
Shale
4601
1.5
NO
29
NO
3.8
0.01
1.0
0.036
0.035
57
NO
0.1
0.092
0.07
1.1
3.2
0.06
ND
NO
7.4
<0.5
0.034
ND
<0.4
0.28
1.7
(8)
Hydro-
treated
4606
0.040
<0.01
<0.5
<0.005
0.052
ND
ND
0.010
0.030
0.24
ND
0.002
<0.005
ND
0.15
<0.05
ND
ND
ND
<0.3
<0.5
0.003
ND
ND
<0.03
0.064
Heavy "
Fuel Oil
From
Shale
011 <9)
0.68
3.5
0.75
0.11
0.19
0.53
0.03
0.054
3.1
2.5
0.15
2.6
0.44
0.096
0.76
<0.3
0.035
sU8)
on
JP-5
(4608)
0.048
<0.02
0.5
<0.01
ND
<0.02
<0.09
ND
<0.02
<0.01
ND
ND
<0.02
ND
0.14
ND
<0.06
ND
ND
ND
ND
ND
ND
ND
NO
<0.02
(8)
Shale
011
JP-8
(4609)
0.056
<0.02
ND
<0.01
ND
<0.02
<0.06
ND
<0.02
<0.01
ND
ND
<0.02
ND
0.06
ND
<0.06
ND
ND
ND
ND
ND
ND
ND
ND
0.02
(10)
Domestic
Crude
011
(Avg)
0.17
0.19
0.17
ND
ND
ND
0.46
38.7
0.17
ND
2.8
15.7
2.8
(ID
No. 6
Fuel
011
19
1.0
<0.15
120
<0.15
2.3
1.2
1.8
16
NR
25
0.4
7.0
141
37
0.8
<0.15
0.9
21
<0.2
1
<0.1
1
48
4
0.8
(10,12
Petroleum
Residual
011
0.3
0.11
0.67
0.09
2.0
2.2
1.8
10.0
7.3
0.02
2.1
2.3
50.1
0.04
0.04
0.14
5.41
57.1
0.19
Petrol eunf ^
Residual
011
75
0.2
0.02
0.3
4
120
0.2
3
3
2.5
150
0.01
75
2.5
0.25
35
120
2
0.02
1
300
0.3
0.1
0.2
0.4
180
4
2
I
00
a. Based the elemental and1.yr.1s of the ash and 0.008% ash content
-------
Additional chemical characterization data are contained in Table E-4.
The aromatic content of the 410 -698 F distillate from shale oil was about
29 weight percent. Similar distillate products from two petroleum crudes
had only 18 percent or less aromatics. One important difference between
crude oil and crude shale oil is the presence of significant amounts of
olefins in crude shale oil. Olefins are more reactive than paraffins and
tend to make crude shale oil less stable than crude oil.
E.I.2 SHALE OIL DERIVED GASOLINE STOCKS
Gasoline was produced from both the 10,000 barrel and 100,000 barrel
retort and refining efforts under the DOD shale oil program. Table E-5
compares the two shale oil gasolines produced to military specification and
to common regular leaded and unleaded gasolines. The Toledo run was not
reformed; it would need to be, to be used. The Gary Western run was
reformed, but still had a low octane rating and would not be suitable for
use. The data in Table E-5 indicate that the Reid Vapor Pressure (RVP) of
the reformed shale oil gasoline is slightly higher than that of the regular
leaded and unleaded gasolines as well as the military specifications.
Other data generated by Shelton (Reference 35), however, indicate RVPs of 7
to 15 for petroleum gasolines. Hence, it is not clear whether there would
be significant differences in fugitive emissions between the reformed shale
oil gasoline and other gasolines. Table E-6 provides more details on the
results of reforming on the chemical make-up of the gasoline. While the
Research Octane Number (RON) is increased and nitrogen contents decreased,
the aromatic contents increased dramatically at the expense of the
naphthenes. The presence of large amounts of aromatic compounds might
affect the properties of shale oil gasoline and will certainly affect the
consequences of shale oil gasolines on health.
E.I.3 SHALE OIL DERIVED JP-5
The results of the DOD 10,000 barrel (Gary Western) and 100,000 barrel
(Toledo) refining of Paraho shale oil for JP-5 fuels are reported in Table
E-7. The Gary Western run received only clay treatment while the Toledo
run was both hydrotreated and acid/clay treated. Note that the thermal
stability of the untreated Toledo fuel is poor. However, after the
nitrogen compounds are selectively removed by acid treating, the fuel's
stability as determined by gum and JFTOT (ASTM D-3241) measurements is very
good. In addition, storage stability characteristics of the fuels were
tested by aging the material for 1 month at 140 F and then repeating the
JFTOT ana gum tests. The aging test results for a composite sample of all
treated JP-5 produced at the refinery indicate that this fuel has very good
storage stability properties.
Compared to a typical JP-5 fuel the shale jet fuel has a slightly
lower distillation curve, but one within military specifications. Aromatic
content of both the finished Toledo and Gary Western runs is higher than
the typical JP-5 fuel, but generally within military specifications. Trace
element composition of the JP-5/8 fuels appears to be quite low (Table E-3)
Arsenic, at 0.5 ppm, appears to be the element with the highest
E-9
-------
TABLE E-4. CHEMICAL CHARACTERIZATION OF HEAVY DISTILLATES
SHALE OIL AND PETRO CRUDE
Oil Samples
Paraho Oil Shale14
Saturates
Olefins
Aromatics
Wt %
Whole
Oil
41
27
24
Superior TOSCO Oil Shale14 j
Saturates i, 39
Olefins : 29
Aromatics
Union "B" Oil Shale'5
Saturates
\ 30
19
Olefins ! 7
Aromatics
Nigeria, Bass River Crude Oil
Saturates
Olefins
Aromatics
41
California (Huntington Beach) Crude^ ,
Paraffins
Naphthene
Aromatic
Wt % of Total Hydrocarbon Fraction
410-698 698-985 <995°F
Distillation Distillation Residue
30
25
28
26
33
29
^
17.8a
b
??b
17
35
24
35
32
22
42
21
12
46
29
20
48
J400-650°F
D482-572°F
E-10
-------
TABLE E-5. SHALE OIL GASOLINE STOCKS ANALYSES
Property
API Gravity
RVP, psi
Distillation (D-86)
IBP, °F
10
50
90
EP
% Recovered
%Residual
Paraffins
Naphthenes
Alkyl benzenes
Indans + Tetralins
Aroma tics
Olefins
Nitrogen, Wt %
Research Octane, Clear
Sulfur, Wt %
Toledo 0>»a
54.7
5.6
200
249
283
317
370
98.0
1.0
49.95
34.0
15.20
0.51
0.32
0.078
47(2)
Gary Western (9)
11.9
86
136
192
342
395
—
1.0
44.0
8
—
—
—
36
0.03
87
0.007
Regular ,,,
Leaded GasolinelbJ
61.8
9.6
87
123
209
342
412
98
1.0
—
—
—
—
—
23
0.49
93.4
0.01
MIL-G-3056C(9)
7 - 9
—
131 - 158
194 - 239
293 - 356
—
—
2 (Max)
—
—
—
—
—
—
—
95
0.15
Unleaded Gasoline^ '
58.2
9.2
87
128
225
342
1.8
—
—
—
—
—
29
0.05
91.0
0.003
a Unreformed
-------
TABLE E-6. COMPARISONS OF HYDROTREATED AND REFORMED GASOLINE--,
FROM PILOT PLANT STUDIES OF SHALE OIL UPGRADING
Property Gasoline Hydrotreated Gasoline Reformed
C6 157°C C6 157°C
API Gravity 57.5 50.5
Research Octane Number 47 93
Paraffins, Vol % 58.9 42.1
Naphthenes, Vol % 30.7 6.8
Aroma tics, Vol % 10.4 51.1
H/C Molar 2.03 1.61
Nitrogen, PPM 400 0.5
E-12
-------
TABLE E-7. SHALE OIL JP-5 ANALYSES
Untreated JP-5
API Gravity
Flash, °F
Freeze, °F
Existent gun (D-381) Mg/lOOcc
Distillation (D-86)
IBP, °F
10
50
90
EP
Nitrogen, Wt %
Paraffins, Vol %
Naphthenes, Vol %
Aromatics, Vol %
Treated JP-5
API Gravity
Nitrogen, PPM
TAN, mg KOH/gm
WSIM
Existent gum Mg/lOOcc
JFTOT at 500°F
Visual
Max Spun Rate
Max rP mm Hg
Paraffins, Vol "'=
Naphthenes, Vol %
Aromatics, Vol ^
(9)
Gary Western
44.4
140
-30
144.2
342
376
426
492
514
25.8
a
Gary Western
44.4
58
113.2
25.6
_ . .0)
Toledo
42.7
158
-57
Not Run
370
384
400
436
480
0.29
42.5
36.0
21.5
b
Tol edo
43.6
0.5
0.005
95
1.4
1
0
0.5
43.7
34.5
21.8
Mil Spec
API gr <48
140 Min
-51 Max
7.0 Max
R
401 Max
R
R
554 Max
—
—
—
25% Max
Mil Spec
36
-------
concentration. No petroleum based analyses were available, but that level
of arsenic should not be significant.
E.I.4 SHALE OIL DERIVED DIESEL FUEL MARINE (DFM)
The Gary Western and Toledo refinery DFM runs are compared to military
specifications in Table E-8. The improved nitrogen removal possible by
hydrotreating and acid/clay treatment is evident from the comparison
between treated Gary Western and Toledo runs. It is expected that the
product should have good combustion properties because the high octane
number (50.1) and the hydrogen weight percent (approximately 13 percent).
E.I.5 SHALE OIL DERIVED RESIDUAL FUELS
The residual fuel produced during the Toledo run met all military
specifications (except for pour point) for a low sulfur, high power No. 6
fuel oil. The sulfur concentration was well below the military
specification and that of a typical No. 6 fuel oil (Table E-9). Arsenic
levels and trace metals are at or below petroleum residual fuel analyses
(Table E-3). In particular, the vanadium content is very low and should
lead to lower H^SO^ emissions during combustion.
E.2 PHYSICAL AND CHEMICAL CHARACTERIZATION OF DIRECT LIQUEFACTION
LIQUIDS (SRC II, H-COAL, AND EDS)
The following sections discuss the physical and chemical composition
of raw and hydrotreated direct liquefaction products.
E.2.1 DIRECT LIQUEFACTION OILS
All three of the major direct coal liquefaction processes, SRC II,
H-Coal, and Exxon Donor Solvent (EDS), can be run to produce different
process oils. For example, H-coal can be run in a boiler-fuel mode
(maximizing residuum) or in a syncrude mode (wide range boiling fractions
production). This section presents data for the syncrude mode (H-coal),
raw process liquid (EDS), and whole process oil (SRC II). The physical
properties of these three liquids are shown in Table E-10, and are compared
to Arabian light and heavy crudes. Because coal type can affect the
product, information on SRC II liquids from Illinois No.6 (high sulfur
coal) and Wyodak (low sulfur coal) are included. In general, the syncrudes
from the three processes are much more dense than the petroleum crudes.
However, because the viscosities of the syncrudes are much lower than the
petroleum crudes, there should be no pumping problems. The raw syncrudes
also exhibit a low pour point, which will aid in handling and transfer
operations.
While the sulfur content of the raw syncrudes would classifiy them as
a low sulfur feed, it and the high nitrogen levels are too high for the
catalysts used in later refinery steps. Before use, the raw syncrudes will
be upgraded via hydrotreating to remove the sulfur and nitrogen. The
hydrotreated syncrudes for SRC II and H-coal are also listed in Table E-10.
E-14
-------
TABLE E-8. SHALE OIL DFM ANALYSES
Untreated DFM
API Gravity
Pour, °F
Flash, °F
Distillation (D-86)
IBP
10
50
90
EP
% Res
Nitrogen, Wt %
Cetane Index
Treated DFM
API Gravity
Carbon, Wt %
Hydrogen, Wt %
Nitrogen, ppm
Paraffins, Vol %
Naphthenes, Vol %
Aromatics, Vol %
TAN, Mg KOH/gm
Cetane Index
ASTM 2274 Mg/100 cc
(ace. Oxid. test)
Distillation (D-86)
IBP
10%
50%
90%
EP
Gary Western
(9)
Gary Western v '
33.2
86.4
12.62
2800
34 35
55.2
446
525
599
662
702
Toledo(1)
36.8
0
162
396
456
512
562
582
1.0
0.33
52.5
Toledo(a)
38.1
86.27
13.28
3.9
45.5
25.5
29.0
0.010
50.1
0.51
Mil Spec(1)
R
20 Max
140 Min
R
675 Max
725 Max
3 Max
45 Min
Mil Spec
R
—
—
0.30 Max
45 Min
2.5 Max
a Hydrotreatment + acid/clay
E-15
-------
TABLE E-9. SHALE OIL RESIDUAL FUEL ANALYSES
Property
API Gravity, 60°F
Pour Point, °F
Rams Bottom Carbon, Wt
Asphaltenes, Ut
Vis. at 210°F, CST
Distillation (D-2887)
IBP, °F
10
50
90
EP
Carbon Wt ^
Hydrogen, Wt ~'*
Nitrogen, Wt %
Oxygen, %
Sulfur, %
Saturates, Vol %
Aromatics, Vol %
Iron, ppm
Arsenic, ppm
Vanadium, ppm
Sodium, ppm
Potassium, ppm
Gary
Western
30
90
—
85.8
11.3
1.4
0.992
0.5
Toledo(l )
29.6
80
0.096
0.059
2.00
331
582
732
900
1032
86.71
12.75
0.44
182 ppm
20 ppm
57. la
42.9s
0.10
0.4
0.02
0.6
0.6
No. 6 nn
Fuel Oil u u
25.0
95
—
—
—
—
—
—
—
—
87.02
12.49
0.23
0.24
Fuel Oil,
Burner , .
MIL-F-859F ^>
11.5 (min)
15 (max)
—
—
—
—
—
—
—
—
—
—
—
—
3.5 (max)
—
—
—
—
—
—
Pilot plant studies
E-16
-------
TABLE E-10.
PHYSICAL PROPERTIES OF SRC II, H-COAL AND EDS
RAW PROCESS LIQUIDS
Property
Gravity, API 0 60 F
Kinematic Viscosity I? 100 F. CSt
Pour Point, F
H2 Consumption (scf/bbl)
Molecular wt.
Ultimate Analysis
Carbon, wt%
Hydrogen, wt%
Sulfur, wtS
Nitrogen, wU
Oxygen, wt*
Ash, ppm.
Distillation Temperature, °F
I. 8. P. (D-86)
10
50
90
EP
St./5 (Simulated GC), F
10/30
50
70/90
95/99
SRC 11
Whole
Process
Oil (Ib)
18.6
2.196
<-80
-
132
84.61
10.46
0.29
0.85
3.79
40
154
281
438
597
850
56/189
241/379
424
473/562
642/820
SRC II
High
Severi ty
Hydrptreat-
Ing 09)
39.3
3100
86.2
13.8
5 ppm
0.25ppm
40 ppm
65/181
215/276
365
410/499
546/648
SRC II
Intermed-
iate
Hydrotreat-
ment (19)
32.7
2000
88.2
11.8
21 ppm
52ppm
680ppm
66/179
213/286
380
422/528
581/705
Wyodak
H-coal
Syncrude
(20)
35.1
1.225
-
~130
86.20
12.74
0.041
0.17
0.85
<20
53/156
173/261
354
429/535
602/785
Wyodak
H-coal
Medium
Severity
Hydrotreat-
treatment
(20)
41.4
-45
838
0.64ppm
0.65ppm
H-Coal
Illinois
No. 6
Syncrude
(20)
25.8
1.645
-
147
86.96
11.39
0.32
0.46
1.80
90
56/177
213/333
404
476/588
654/765
H-Coal
Illinois
No. 6
High Sev-
erity
ydrotre-
atment
(20)
35.3
1613
5.4ppm
O.lSppm
EDS
Raw
Liquid
Product
(21)
\ ^ • )
3.5
-
89.22
8.66
0.49
0.71
1.93
403
930
Arabian
Light
Saudi
Arabia
(4'>
VH l
33.4
6.14
-30
1.8
190
650
1050
Arabian
Heavy,
Saudi
(4)
28.2
18.9
-30
2.84
215
750
1200
-------
Clearly, even moderate hydrotreating is capable of reducing the nitrogen
levels to 50 ppm. Hydrotreatment also reduces the fraction of high boiling
point materials, as a result of converting aromatic compounds to
naphthenes. Table E-ll contains information on the chemical composition of
the raw and hydrotreated SRC II syncrudes and the hydrotreated H-coal and
EDS process liquids. Hydrotreatment can virtually eliminate the aromatic
content of SRC II syncrude; while this might be a control method for
hazardous aromatics (SRC II contains 9 percent phenols), process economics
will probably preclude severe hydrotreatment. Studies are needed to
determine what degree of hydrotreatment is required to reduce hazardous
aromatic compounds to an acceptable level.
E.2.2 DIRECT LIQUEFACTION NAPHTHA
An important intermediate product is the naphtha feedstock obtained
from the direct liquefaction processes which will be used to produce
transportation fuels. Table E-12 contains the physical data on the
coal-derived naphtha as received and after hydrotreating. Hydrotreatment
raises the API gravity slightly, and almost entirely removes the sulfur and
nitrogen content of the naphtha. While the aromatic content is reduced,
the olefinic fraction is removed even under mild (500-800 SCF H^/bbl)
hydrot reatment.
A detailed look at the change in the chemical composition of the
naphthas before and after hydrotreating is given in TaMes E-13 and E-14.
Before hydrotreating, the polar fraction contained significant amounts (3.9
percent) of phenol. After treatment, the polar fraction is removed. Based
simply on the known toxicity of phenols, one would expect a reduced level
of hazard associated with the hydrotreated naphtha.
E.2.3 GASOLINE FROM DIRECT LIQUEFACTION PROCESSES
The naphtha feedstock discussed in Section 2.2 is not suitable for
direct use as a gasoline because of its low octane number (40-70). Another
step, reforming, is required to produce a commercial-grade gasoline. Table
E-15 shows the results of reforming the naphthas previously discussed. The
aromatic content (Table E-16) was dramatically increased at the expense of
the naphthenes. A high (91-99) Research Octane Number was obtained.
Compared to the API standard for petroleum gasoline, the direct
liquefaction gasolines have more aromatics and naphthenes and less
paraffins. Furthermore, the SRC gasoline has more benzene and
hydroalkylaromatics than the petroleum gasoline. The extreme case was the
H-coal sample (636/220-5), which contains 62 weight percent of C8 or higher
alkylbenzenes. Table E-17 provides an overview of the results of reforming
the naphthas to gasoline. The specific composition of the chemical classes
may be different as noted above for the aromatics, but in general they are
similar to the petroleum-based gasoline.
E-18
-------
TABLE E-ll.
CHEMICAL COMPOSITION OF SRC II, H-COAL AND EDS
RAW PROCESS LIQUIDS
PI
10
Paraffins (total)
Nflphthenus (total)
Monocyeloparafflns
B1cycloparaff1ns
Trlcycloparafflris
Aromatic!, (total)
Alkylbenzer.es
In denes and te
Dlnapthenebenzenes
Napthalenea
i"t 1 r»« 1 U¥
ji)
tal)
'Ins
5
rii
»D
ralln?.
nes
SRC II Whole,,...
Process Oil UB'
WOW- 3666
(1.1)
(10.2)
11.9
8.1
19.9
(55.2)
15.7
26.1
3.7
9,4
SRC II High
Severity (]g>
Hydrotreatment
(3.3)
(93.2)
(3.9)
SRC II
Intermediate
Severity t20'
Hydrotreatment
(1.5)
(16.8)
(18.7)
WYODAK
H-Coal (20)
Medium Severity
Hydrotreatment
(15.3)
(73.2)
(11.5)
H-Coal
Illinois No. 6 .
High-Severity (ZO)
Hydrotreatment
(7.0)
(74. 5)
(18.5)
-------
TABLE E-12. PHYSICAL PROPERTIES OF COAL-DERIVED NAPHTHA
Property
Sample No.
API (? 60 F
Sp. Gr. & 60 F
Distillation ASTM D-86
IBP, F
57
10%
20%
30%
40%
50%
60%
70%
80%
90%
95%
EP F
1 Over
Hydrogen, Wt %
Carbon, Wt %
Sulfur, Wt ppn.
Nitrogen, Wt ppm
Oxygen, Wt ppm
Chloride, Wt ppm
FIA, Vol %
A
P&N
M S Hydrocarbon Types, Vol %
Aromatics/Polars
Naphtheres
Paraffins
Olefins
Bromine Index
RON, Clear
N Jet Gum, m&/100 ml
SRC PROCESS
As Received
3777-1
49.7
0.7809
107
134
157
188
209
226
243
261
279
292
316
346
367
97.5
12.91
85.87
4400
5140
7814
195
-
-
*
23.0
37.1
31.5
8.4k
30. Ob
80.8
12.0
H2 Consumption (SCF/BBL) N/A
NAPHTHA (21>
Hydrotreated
3777-2
52.0
0.7711
136
163
180
J96
209
220
233
249
270
289
311
330
388
98.5
13.66
86.00
0.22
0.8
359
3.8
18.8
81.2
22.0
52.8
25.2
_
101.0
70.9
-
EDS PROCESS
As Received
3531-7
38.4
0.8328
142
178
208
244
268
286
302
316
319
339
348
-
380
-
11.80
86. Z4
9,978
2,097
13,700
18
-
-
r
34.0
42.9
13.2
9.9h
39. b
83.2
44.0
560 N/A
NAPHTHAS*22^
Hydrotreated
3531-12
44.1
0.8058
202
215
226
237
250
264
287
305
322
336
351
360
374
98.6
13.13
86.18
0.1
0.2
98.0
1.0
20.1
79.9
21.62
65.48
12.90
.
124.0
64.5
-
850
H-COAL PROCESS
As Received
3531-1-2
43.7
0.8076
132
170
189
215
233
251
260
292
312
328
251
373
396
99.0
12.80
85.90
1289
1930
5944
23
H
22.8
55.5
16.2
5.5k
19. 3 b
80.3
-
N/A
NAPHTHA <23)
Hydrotreated
3531-4
46.8
0.7936
153
185
199
217
231
246
263
284
306
329
352
367
393
99.0
13.59
86.45
3.9
0'.63
34
4
17.6
63.4
19.0
-
296
66.8
-
480
I
ro
o
a Includes 6.82 Polars
Bromine nun her
c Includes 8.9 , Polars
Includes 4.2% Polars
5.2/0.0 wt/Vol-X not shown
-------
TABLE E-13.
DETAILED CHEMICAL ANALYSIS OF SRC II, EDS, AND
H-COAL NAPHTHAS
Series
CnH2n+2
r u
CnH2n
r u
V2n-2
CnH2n-4
CnH'n-6
CnH2n-8
CnH2n-10
CnH2n-12
CnH2n-5N
CnH2,i-4°
Cnh2n.-6°
CnH2n-7N
CnH2n-4S
CnH2n
CnH2n-2
CnH2n-4
Hydrocarbon Types
Paraffins
Naphthenes
Monocycloparaffins
Gyclopentanes
Cyclohexanes
Bi , Dicycloparaffins
Tricycloparaffins
Aromatics
Alkyl benzenes
Indanes/Tetralins
Dlnaphthenebenzenes
Naphthalenes
Polars
Pyri dines
Furans
Phenols
Naphthenopyri dines
Thiophenes
Olefins3
Monoolefins
Diolefins and/or Monocycloolefins
Triolofins and/or Dicycloolefins
Total
SRC II Naphtha
Wt %
27. &
28.4
-
-
7.1
1.0
17.4
0.7
<0.1
<0.05
3.0
-
4.5
Trace
1.6
1.9
5.1
1.4
100.0
(3777-1) f21)
Vol %
31.5
28.9
-
-
7.2
1.0
15.6
0.6
Trace
Trace
2.3
-
3.2
Trace
1.3
2.1
5.0
1.3
100.0
EOS Naphtha
Wt %
11.3
-
9.8
14.1
10.9
7.4
17.5
8.7
0.5
Trace
-
Trace
9.1
0.1
1.5
2.3
5.4
1.4
100.0
(3531-7)'221
Vol %
13.2
-
10.4
15.0
10.5
7.0
17.0
7.9
0.4
Trace
-
Trace
7.4
0.1
1.2
2.6
5.8
1.5
100.0
H-Coal Naphtha v
(3531- 1-2- t23)
Vol %
16.2
48.1
-
-
7.2
0.2
12.7
5.8
-
0.1
0.8
.
3.1
-
0.3
1.3
3.7
0.5
100.0
ro
aThe total olefin number was obtained by Si02 separation, but the mono-, di-, tri-olefin split is estimated since no calibration coefficients are
available.
-------
TABLE E-14.
DETAILED CHEMICAL ANALYSIS OF SRC II, EDS, AND
H-COAL HYDROTREATED NAPHTHAS
ro
ro
Product Distribution
C3
C4
n-Pentane
Isopentane
Cfi Plus
Total
MS Analysis of Ce Plus Fraction
Hydrocarbon Types
Paraffins
Naphthenes
Monocycloparaffins
Bi, Dicycloparaffins
Tricycloparaffins
Aroma tics
Al kyl benzenes
Indans, Tetralins
Naphthalenes
Total
Hydrotreated SRC- 1 1 Naphtha
(3777-2)
Wt-% Vol-%
0.1 0.1
1.2 1.6
2.4 2.9
0.9 1.1
95.4 94.3
100.0 100.0
Vol-%
25.20
47.28
5.57
0.0
21.53
0.42
0.0
100.00
Hydrotreated EDS Naphtha
(3531-12)
Wt-% Vol-%
0.4 0.5 >
0.1 0.1 )
99.5 99.4
100.0 100.0
Vol-%
12.90
50.15
15.33
0.0
17.82
3.80
0.0
100.00
Hydrotreated H-Coal Naphtha
(3531-4)
Wt-% Vol-%
1.8* 2.4*
98.2 97.6
100.0 100.0
Vol-%
15.96
55.02
9.49
0.09
16.54
2.83
0.07
100.00
Includes 0.4 wt/Vol-% of cyclopentane.
-------
TABLE E-15.
PHYSICAL PROPERTIES OF GASOLINE PRODUCED FROM
DIFFERENT SYNCRUDE FEEDSTOCKSU7)
Raw Feed (Feedstock Fron
Synthetic Crude)
Refining Techniques
First Stage
Second Stage
Gasoline Sample Number
Conditions of Final Treatmer
p-p(base)' PS1
LHSV/LHSV(base)
CFR/CPR(base)
T-T(base)' F
Physical Properties
API Gravity 0 60°F
Octane No. . (RON Clear)
Ultimate Analysis
Hydrogen; wt %
Carbon; wt %
Sulfur; wt, ppm
Nitrogen; wt, ppm
Oxygen; wt, ppm
FIA Analysis, Vol %
Aroma tics
SRC-II Naphtha'21
(3477-2)
Hydrotreating
Flatformed
636/335-2
t
0
1.40
-87
42.1
94.5
10.91
87.61
0.1
0.1
183
66.0
Olefins I 0.0
Paraffins & Naphthenes
Distillation, Temperature °F
IBP
10'.
5Q%
901
EP
32.9
158
183
247
330
411
) EDS Naphtha(22)
(3531-7)
Mild Hydrocr.icking
Platformed
i
1
636/321-3
0
1.54
-85
43.9
96.0
12.01
88.73
0.1
0.3
327
37.1
0.0
60.7
144
17J
255
344
382
H-Coal Gas-Oil (18)
(96-3330A)
Mild Hydrocracking
Series Flow 2nd
Stage Hydrocracking
536/678
-500
1.0
1.18
47-49
51.8-53.4
91.5
---
11.7-32.0
0.1-1.0
91.5-93.6
29.1-34.3
0.0-0.0
65.7-70.9
82-107
122-127
244-232
350-359
385-393
H-Coal Gas-Oil (1Q)
(9C-3330A)
Heavy Hydrocracking
Simple 2nd Stage
Hydrocracking
601/749-751
-500
0.725-1.45
1.25
20-50
48.8-51.0
---
...
...
...
...
23.6-35.7
0.0-0.0
64.3-76.4
30-70
77-158
215-242
320-340
365-459
(2&\
H-Coal Gas-Oil u '
(37-1117/8)
Moderate Hydrotreating
Fluid Catalytic
Cracking
593/255-1,2,3,4,5
-10
1.03-1.56
2-47
43.1-45.2
95.5-96.9
—
..-
...
---
45.2-507
4.2-6.2
44.5-49.5
120-130
157-161
230-245
344-336
410-422
H-Coal Naphtha (23)
(3531-1-2)
Moderate Hydrotreating
Platformed
636/2201'2'3'4'5
0
1.48
-57
35.3-36.9
97.7-99.8
10.74
88.92
...
—
...
-"
156-165
200-204
272-277
367-372
425-462
I
ro
CO
-------
TABLE E-16. COMPARISON OF COAL-DERIVED GASOLINE COMPOSITION^?)
Composition
Paraffins, Wt %
Naphthenej., Wt %
Monocycloparaff ins - C2~C,,
Dicycloparaffins
Aromatics, Wt %
Benzene
Toluene
Alkyl benzene Ca-C,,
o 1 J
Indans/tetral ins. Wt %
c8-cn
Naphthalenes, Wt %
C10"C12
Polars, Wt *
VS
Olefins, Wt %
Unidentified, Wt %
Gasol ine from
Petroleum (26)
Sample No. ~l
API Standard
56.8 a,b
2.4C
0.0
0.12
21.8
7.0
0.22
0.09
0.00
7.9
3.7
Gasoline from
SRC- 1 1 Naphtha
Hydrotreated(21 )
Sample No.
636/335-2
23.9 d«9
8.3
0.7
18.0
19.0
27.9
2.1
0.0
0.0
0.0
--
Gasoline from
EDS Naphtha
Hydrocracked
8 Platformed'22
Sample No.
636/321-3
18.8 d,g
16.6
2.2
0.8
12.6
43.6
3.4
0.1
0.0
0.0
—
Mild Hydrocracking
Series Flow
Hydrocaracking^"
Samole No.
536/678-47
38.3 b.e
23.5
--
5.9
7.7
16.0
0.0
0.0
0.0
0.0
--
Gasoline from
H-Coal Gas-Oil
Heavy Hydrocracking (
Simple Hydrocracking
Samole No.
601/749-23
34.4 b,f
39.5
--
5.1
6.5
14.6
0.0
0.0
0.0
0.0
--
Gasol ine
from H-Coal
Naphtha Moderate
26)Hydrotreatment
Platformedfl22)
Sample No.
636/220-5
18.85 d,h
8.80
0.63
--
61.99
7.72
2.01
--
--
—
I
ro
Includes 21.9% C4 X C& Paraffins
C4-C-|3 inclusive
Cg-Cg only
Volume %
Includes 31.5% C4 X C& paraffins
Includes 16.6% C4 X C5 paraffins
Cg to C.jg indlusive
C& + fraction only
-------
TABLE E-17. GASOLINE COMPARISON-SPECIFICATIONS, PETROLEUM, AND COAL-DERIVED^27)
Gasoline
Gasoline
Specifications
Petrol eum-deri ved
Gasoline
Coal -derived
Gasolines:
SRC-II Naphtha
EDS Naphtha
H-Coal Gas Oil
Treatment 1
Treatment 2
Treatment 3
Sulfur
Content
(wt ppm)
<1000
75-240
0.1
0.1
12-32
--
Distillation
End Point
(°F)
437
340-345
411
382
385-393
Gravity
(°API)
55-65
57-58.4
42.1
43.9
52-53
365-459 ! 49-51
i
Aromatics
(Vol %)
--
24-36
--
29-34
24-36
45-50
Olefins
(Vol %)
--
5-8
--
0
0
5-6
Saturates
(Vol %)
--
56-59
--
66-71
64-76
45-49
I
rv>
en
-------
E.2.4 NO. 2 FUEL OIL FROM DIRECT LIQUEFACTION
Acceptable blending stock for No. 2 fuel oils can be produced from
crude by either single-stage or two-stage hydroprocessing techniques.
Results from EDS and H-coal crude are shown in Table E-18. The physical
properties of synfuel blending stock were similar to those of a petroleum-
derived No. 2 fuel oil. The synfuels have a low nitrogen and sulfur
content; they also tend to have slightly lower API gravities and a higher
flash point than required by API No. 2 fuel specifications. Distillation
temperatures at 90 percent are within the acceptable specification range.
E.2.5 JET AND DIESEL FUELS FROM DIRECT LIQUEFACTION
H-coal and SRC II syncrudes were hydroprocessed in the same plant as
jet fuel, diesel fuel, and No. 2 fuel oil (Table E-19). These synfuels are
similar to the jet fuel and No. 10 diesel specifications shown in Table
E-20. Heavier hydroprocessed products (not shown here) meet the No. 20
cold climate diesel specifications.
E.3 CHEMICAL CHARACTERIZATION OF INDIRECT LIQUIDS
The indirect coal liquefaction products characterized in this section
include gasoline from Fischer-Tropsch synthesis, gasoline from the Mobil-M
gasoline conversion process, and methanol. The Fischer-Tropsch synthesis
unit also generates a stream of oxygenated compounds that is described in
the following paragraphs. The term "indirect liquefaction" refers to the
fact that coal is gasified before the liquids are produced. Some of the
common gasifiers (e.g., Lurgi and Synthane) generate streams of tars, oils,
and phenols, and these are also described in the following paragraphs even
though they are produced in relatively minor amounts.
E.3.1 FISCHER-TROPSCH GASOLINE
Fisher-Tropsch gasoline is reported to be sulfur and nitrogen free
(Reference 31). In addition, the aromatics content as shown in Table E-21
(17 percent) is lower than that of typical petroleum gasolines (24 to 33
percent), as shown in Table E-17. The saturates content is similar to that
in petroleum-derived gasoline, but the olefin content of Fischer-Tropsch
gasoline is much higher than that of petroleum gasoline. The absence of
nitrogen and sulfur compounds means that heterocyclic compounds involving
these elements will also be absent. The advantage in terms of SOX and NOX
emissions is probably not significant because petroleum gasolines tend to
be low in nitrogen and sulfur as well. The Fischer-Tropsch synthesis
reactor also produces a wide variety of oxygenates. The extent to which
these are present in the gasoline product is unknown.
The Reid vapor pressure for Fischer-Tropsch gasoline is estimated to
be 10 (Reference 34). This is in the middle of the range of Reid vapor
pressures for petroleum gasolines (7 to 15) (Reference 35). Thus, evapora-
tive emissions from handling and storage should be similar in quantity to
those from petroleum gasoline.
E-26
-------
TABLE E-18.
PROPERTIES OF NO. 2 FUEL OIL REFINED FROM
PETROLEUM AND SYNCRUDE(27)
I
ro
Parameter
Gravity, °API
Molecular Weight
Pour Point, °F
Flash Point, °F
Viscosity, cSt, 100°F
Distillation Temperature, °F
IBP
10, LV %
50,LV%
90,LV%
EP
Bottoms %
Ultimate Analysis
Hydrogen, Wt%
Carbon, Wt %
Sulfur, Wt ppm
Nitrogen, Wt ppm
Oxygen, Wt ppm
SPECIFICATION CRUDE OIL^29'
5Q% virgin
50% cracked
Sample No.
API #78-4
30 36.2
— —
20 -10
100
2.0-3.6 2.6
437.0
470.0
511.0
540-640 572.0
610.0
— —
<5,000 2,500
EDS COAL^30) H-COAL ATMOSPHERU
OIL DISTILLATE STILL BOTTOMS
first stage
hydrocracking
Sample No.
3532-7
25
220
-75
136
2.37
367.0
412.0
470.0
545.0
592.0
1.0
12.03
87.80
2.0
0.6
718.0
second stage
hydrocracking
Sample No.
3532-20/26
27.4/27.9
—
—
—
2.28/2.06
397/400
408/404
450/433
539/540
585/583
1.0/1.5
23.17/12.20
86.93/87.93
84/1 39
0.6/0.2
723/415
second stage
hydrocracking
Sample No.
3531-35/36
—
—
—
—
—
—
—
—
600
—
23.61/12.50
86.69/87.33
20.2/7.1
0.2/1.9
102/483
-------
TABLE E-19. PHYSICAL PROPERTIES OF JET/DIESEL FUELS FROM COAL SYNCRUDE(27)
Parameter
Processing Conditions
Catalyst Temperature °F
LHSV
Hydrogen partial pressure, psig
Recycle Gas Rate, SCF/bbl
Catalyst
Physical Properties
Gravity, °API
Flash Point, °F
Distillation Temp. End Point, °F
Viscosity @ 100°F, cSt
Cu Corrosion
Aromatics, LV %
Smoke Point, (min)
Freeze Point, °F
Thermal Stability
JFTOT P 260
Existant Gum, ppm
H-Coal
111. #6 Coal
Burning Star
Mi ne
— Single
750
0.5
2232
7921
1 CR-113
37
108
554
No. 1
2.3
23
-53
No. 1
P 0
1
Sync rude
Wyodak
Coal
Stage Hydro Tre
(several )
752
1.0
2257
7743
1 CR-113
39.7
>100
<554
No. 1
3.6
21
<-40
—
—
1
SRC LI Syncrude
Pittsburgh Seam
Blacksburg, W.Va.
#2 Mine, Conoco Coal
750
0.5
2306
13752
1 CR-113
36.3
>100
<554
No. 1
5.0
22
-75
No. 1
P 0
2
Physical properties of +250°F boiling range product
E-28
-------
TABLE E-20. DETAILED SPECIFICATION FOR JET FUEL, AND DIESEL FUEL(27)
I
ro
Parameters
Flash Point, °F (min)
Smoke Point, (min) (32)
Pour Point, °F (max)
Freeze Point, °F
Water/Sediment, Vol % (max)
Ex is tan t Gum, ppm
Carbon Residue on 10% Bottoms, % (max)
Thermal Stability
Ash, Wt % (max)
JFTOT @ 260°C
Distillation Temperature, °F
10% (max)
90% (min)
" (max)
End Point
Kinematic Viscosity, cSt
@ 100°F (min)
(max)
Aromatics, LV %
Gravity, °API (min)
Copper Strip Corrosion (max)
Jet (4)
Fuel v '
>100
> 20
—
<-40
--
< 7
--
No. 1 or 2
—
P<25 min
--
--
—
570
--
--
< 20
37-51
No. 1
Diesel Specifications
ASTM D-975-78 (33)
All Typical Cold
Climates Climates Climates
No. 1 D No. 20 No. 2D
>100 >100 >125
__
__
—
--
__
—
__
<0.01 <0.01 <0.01
—
__
--
<550 <540-560 <560
— — __
1.3-2.4 1.9-4.1 1.7-4.1
__
--
__
No. 3 No. 3 No. 3
Sulfur, Wt % (max)
Octane No.
< 0.5
> 40
< 0.5
> 40
< 0.5
> 40
-------
TABLE E-21. COMPARISON OF PRINCIPAL UNLEADED GASOLINE SPECIFICATIONS
WITH ESTIMATED FISCHER-TROPSCH GASOLINE PROPERTIES
CASE II ^ '
Properties
Gravity, °API
Octane Numbers
Research
Motor
(Research + Motor) /2
Volatility
Reid Vapor Pressure, Ib
Distillation, OF
IBP
10%
30%
50%
70%
90%
EP
V/L Ratio (+20), OF
Sulfur, wt %
Composition, vol %
Paraffins
Olefins
Naphthenes
Aromatics
Molecular Weight
Estimated F-T
Unleaded Gasoline
67.2
91
83
87
10.0
86
108
137
186
249
335
420
0127
Nil
60
20
3
17
93
Specifications
82 min
87 min
158 max
170/250 min /max
374 max
437 max
0140 max
0.10 max
20 max (Target)
E-30
-------
E.3.1.1 F-T By-Product Chemicals Composition
Approximately 5 to 12 (weight percent) of the Fischer-Tropsch
synthesis product is by-product chemical oxygenates (Reference 28). Table
E-22 shows the distribution of these products. At the SASOL plant the
aldehydes are hydrogenated and methanol is used on-site as make-up in the
Rectisol gas cleaning unit. Ethanol, propanol, butanol, pentanol, acetone,
MEK, and a higher alcohol fraction are the products distributed
commercially (Reference 31).
E.3.1.2 Tars, Oils, and Phenols
Depending on the type of gasifier used, by-product tars and oils from
the gasification unit may be produced. Tables E-23, E-24, and E-25 present
data on the composition of typical gasifier tar and oil by-products. It
can be seen from these tables that coal type and source are important
factors in determining the composition of the tars and oils. Table E-23
shows that di- and tri-aromatics are the primary constituents of tars from
the Synthane gasifier. N-heterocyclics, phenols, and benzene are present
in much smaller but significant quantities, and pentacyclic aronatics are
only present in trace amounts.
Table E-25 presents the composition of an oil sample produced by a
Lurgi gasifier. It is primarily composed of benzene and alkylated
benzenes. Table E-25 shows the elemental composition of unseparated tars
and oils also produced by a Lurgi gasifier. It can be seen that a wide
range of trace and minor elements can be present.
Table E-26 shows the estimated composition of the crude phenol
by-product stream from a Lurgi gasification unit. More than 70 percent of
the mixture is expected to be monohydric phenols. Other organics such as
benzene may also be found in the phenol stream.
TABLE E-26. ESTIMATED COMPOSITION OF PHENOL BY-PRODUCT STREAM
Phenol Class/Compound Percent (wt)
Monohydric Phenols 74
Phenol 50
Cresols 17
Xylenols 4
Catechols 20
Resorcinols 7
E-31
-------
TABLE E-22. BY-PRODUCT,CHEMICALS PRODUCED BY FISCHER-TROPSCH
SYNTHESIS ( '
NON-ACID CHEMICALS
Acetaldahyde
Propionaldehyde
Acetone
Methanol
Butyraldehyde
Ethanol
NEK
i -Pro pa no 1
n-Propanol
2-Butanol
EEK-MPK
i-Butanol
n-Butanol
N-Butylketone
2-Pentanol
n-Pentanol
Ccr alcohols
Wt %
3.0
1.0
10.6
1.4
0.6
55.6
3.0
3.0
12.8
0.8
0.8
4.2
4.2
0.2
0.1
1.2
0.6
E-32
-------
TABLE E-23. COMPOSITION OF BENZENE-SOLUBLE TARS PRODUCED IN SYNTHANE
GASIFICATION PROCESS { ;
Compound/Class
Mono Aroma tics
Benzene
Phenols
Di Aromatics
Naphthalenes
Indans/Indenes
Naphthols and
Indanol s
Tri Aromatics
Phenyl na ph tha 1 enes
Acenaphthenes
Fluorenes
Anthracenes/
Phenanthrenes
Acenaphtnols
Phenanthrols
Tetracyclic Aromatics
Pericondensed
(benz^nthracenes,
chrysene)
Catacondensed
(pyrene, benz-
phenanthrenes)
Pentacyclic Aromatics
Heterocycl ics
Dibenzofurans
Dibenzothiophenes and
Benznaphthothiophenes
N-Heterocyclics
Type/Origin of Coal
Bituminous
(Illinois)
Lignite
(N. Dakota)
Subbituminous
(Montana)
Volume %
2.1
2.8
11.6
10.5
0.9
9.8
13.5
9.6
13.8
--
2.7
7.2
3.0
trace
6.3
6.2
10.8
4.1
13.7
19.0
5.0
11.4
3.5
12.0
7.2
10.5
2.5
--
3.5
1.4
5.2
1.0
3.8
3.9
5.J
15.3
7.5
11.1
6.4
11.1
9.7
9.0
4.9
0.9
4.9
3.0
5.6
1.5
5.3
Bituminous
(Pennsylvania)
1.9
3.0
16.5
8.2
2.7
7.6
15.8
10.7
14.8
2.0
--
7.6
4.1
trace
4.7
2.4
. 8.8
E-33
-------
TABLE E-24. COMPOSITION OF TARS AND OILS PRODUCEDJjY GASIFICATION
OF VARIOUS COALS IN LURGI GASIFIERS v '
CM) Nta*er
Coil Typc/OrlQin
Production IUt*, kg/tonnt
coal (dry basis)
Elemental Composition (»t I)
C
H
N
%
0
Ash
Phenols
llinor and Trace Elements (pprr
*9
As
B
Bi
Be
Br
U
Ce
Co
Cr
Cs
Cu
f
&a
Ge
Hg
Li
No
*1
Nt
P
Pt>
Rt>
Sb
Sc
Se
Sn
Sr
T»
u
V
u
1
Zn
Zr
A)
Ci
ft
I
".a
SI
Tt
1
Subb1tun1nous
Montana Rosebud
Tar Oil
26 2f>
83.1 81.3
7.7 9.2
0.65 0.5
0.28 0.5
8.2 8.5
0.05 0.03
5.3 19.1
r)
2
B1u»(noul
Illinois M
T«r Oil
27 5
85.5 84.8
6.4 7.8
1.2 0 7
1.7 24
5.2 4.3
0.03 0.01
2 20.1
3
aitt«1noui
Illinois »S
Tar Oil
35 6
85.9 84.9
6.4 7.7
1.2 0 5
2.4 2 3
4.2 4.7
0.01 0.01
4.7 19.2
4
BlUMlnoMS
Pittsburgh M
T«r Oil
38 8
88.5 87 3
5.9 7.6
0.9 0.5
1.5 1.5
3.2 3.2
0 01 0.01
1 10
„
..
--
..
..
5
Bltwtnous
S. African
Tar 01 1
15 8
0.3 0.25
4 26
50 0.5
0.8 0.05
<.04 '.04
-.05 <0.3
4 <0.3
4 <0.5
0.4 .0.1
2.5 0.3
2.5 1.2
50 1
0.8 0.5
S 0.2
-
6
llgnitt
N Dakota
Tar 011
IS B
0.65 0.52
0.45
7 24
1 4
2 S60
<0.1
«0.1 -0.2
•0.3 <0.5
4
0.6 0.9
5 4
3 2
51 5
01
2.9 0.16
0.7 0.1
2 6
11 0.7
J 2
90 2
14 4
2 0.2
0.7 2
0.2 0.4
84 0 3
0.9
3 0.2
3 1
0.9 2
10 1
1500 150
2600 230
1500 100
178 35
700 390
4200 180
92 5
764 19
9
Lignite
N. Dakota
Tar DM
15 6
2 1 7
20 30
15 O.S
01 0 05
«0.1 '0 1
0.05 0.02
1 0.6
0.1 2
12 .06
«0.1 <0 1
0.5 O.S
0 02 0.02
10 15
1 5 0.15
.0 05 -0 02
02 -0 01
0.2 -0 05
5 -1
0.05 0 IS
6 0 4
E-34
-------
TABLE E-25. ORGANIC COMPOSITION OF LURGIvOIL PRODUCED AT THE
WESTFIELD LURGI FACILITY (*3)
Compound/Class
Paraffins
Olefins
Aromatics
Sulfur (total)
Benzene
Toluene
Xylene and
ethyl benzene
Ethyl toluene
Trimethyl Benzenes
Styrene
Indane
1,2-benzofuran
Indene
Naphthalene
Thiophenes
Concentration (wt
10.71
89.3
19.56
28.40
14.7
2.69
11.8
1.07
1.43
1.09
5.37
1.40
1.77
E-35
-------
E.3.2 MOBIL-M GASOLINE
Mobil-M gasoline is also reported to be free of detectable quantities
of nitrogen and sulfur as well as oxygen (Reference 40). The content of
paraffins, olefins, naphthenes, and aromatics is typical of that of
petroleum gasolines (Table £-27). The Reid vapor pressure is also similar
to that of petroleum gasoline. With Mobil's standard additive package, the
gasoline has passed quality screening tests for carburetor detergency,
emulsion formation, filterability, copper attack, metal corrosion, and
storage stability (Reference 40).
Durene (sym-1, 2, 4, 5-tetramethyl benzene) is a potentially
troublesome component because of its 175 F freezing temperature.
Carburetor plugging can be a problem if durene concentrations exceed 4
percent. Mobil believes that manipulating of process conditions and
blending with conventional gasolines can keep durene concentrations to
acceptable levels (Reference 41).
Based on the Reid vapor pressure, the evaporative emissions from
Mobil-M gasoline should be similar in quantity to the emissions from
petroleum gasolines. The absence of nitrogen, sulfur,'and oxygen indicates
that the product will be free of heterocyclic compounds as well. As with
the Fischer-Tropsch gasoline, the absence of nitrogen and sulfur is
probably not a significant advantage over petroleum gasoline for NO and
SO emissions. x
s\
E.3.3 METHANOL
Methanol (CI-UOH) is a light volatile alcohol. The estimated
composition of a typical crude methanol is shown in Table E-28. The
concentrations of the impurities are expected to vary depending on the
synthesis process used. Crude methanol can be upgraded to meet user needs.
Chemical grade methanol is relatively pure, containing 0.05 percent water.
Technical or fuel-grade methanol, however, will probably contain impurities
such as those listed in Table E-28. Distribution systems may introduce
additional water (Reference 42).
Methanol may also be used as a motor fuel by blending it with
gasoline. Problems with corrosion, phase separation with water, and vapor
lock have been reported (Reference 48). In hot regions of the country,
large, non-ideal increases in the vapor pressure of the blend may require
that some of the lower molecular weight fractions of the gasoline be
removed during summer months (Reference 42).
E-36
-------
TABLE £-27. TYPICAL PROPERTIES OF FINISHED MOBIL GASOLINE^43)
COMPONENTS, WT%
BUTANES
ALKYLATE
C/ GASOLINE
COMPOSITION, WT%
3.2
28.6
68.2
1UU.U
PARAFFINS
OLEFINS
NAPHTHENES
AROMATICS
OCTANE
RESEARCH
56
7
4
33
TOT
MOTOR
CLEAR
LEADED (3 CC TEL/US
REID VAPOR PRESSURE,
SPECIFIC GRAVITY
SULFUR, WT%
NITROGEN, WT%
DURENE, WT%
96.8
GAL) 102.6
PSI 9.0
0.730
NIL
NIL
3.8
87.4
95.8
CORROSION, COPPER STRIP 1A
ASTM
10%
30%
50%
90%
DISTILLATION, °F
117
159
217
337
TABLE E-28. ESTIMATED CRUDE METHANOL COMPOSITION^4'
CH.OH 94.6%
CXOH
dH^OH 2800 ppm
OH 150 ppm
Non-methane HC's 600 ppm
H0 5.0%
E-37
-------
E.4 CHEMICAL CHARACTERIZATION OF COAL GASES
E.4.1 SNG
The primary constituent of SNG is methane, but smaller quantities of
H , CO?, CO, N-, AR, H2S, and C^Hg can also be present. Table E-29 shows a
typical high-Btu product-gas composition. There is evidence that trace
quantities of metal carbonyls may be produced during catalytic methanation,
during gasification, or by reaction of CO and Ni or Fe in piping and other
structural components (Reference 45).
TABLE E-29 TYPICAL SNG COMPOSITION
Concentration
Concentration (vol %)
Carbon dioxide 0.50
Carbon monoxide 0.06
Hydrogen 1.45
Methane 96.84
Nitrogen and argon 1.15
Hydrogen sulfide 0.2 ppm
E.4.2 CHEMICAL CHARACTERIZATION OF LOW-/MEDIUM-BTU COAL GAS
The composition of low- and medium-Btu gas is highly variable and
depends on such factors as coal type, gasifier type, gasifier operating
conditions, and the extent of gas cleaning. It can be expected that gases
will be cleaned to meet user needs. If the bases are to be combusted, it
can also be expected that they will be sufficiently cleaned to satisfy
federal and local air quality regulations.
Table E-30 shows the gaseous species in a typical low Btu gas. Samples
were taken over a week-long period from a Wellman-Galusha gasification
facility using lignite coal. The values in the table represent an average
of the available data taken during the sampling period, thus the calculated
confidence intervals include not only sampling and analytical variance but
also a major contribution from process variability (Reference 47).
Table E-31 shows that a wide range of trace and minor elements may
also be present in the product gas. In addition to the C1-C6 hydrocarbons
shown in Table E-30, a product gas may contain a number of more complex
E-38
-------
organics. Table E-32 lists some that are of particular environmental
concern. In the product gas characterized in Tables E-30, E-31, and E-32,
the combined polynuclear aromatics concentration was more than 3500 ug/SCM
(Reference 47).
E-39
-------
TABLE E-30. GASEOUS SPECIES ANALYSIS SUMMARY:
LOW-BTU COAL GAS ( >
Analysis
Major Components (% ± 2o)
C02
H2
02 + Ar
N2
CO
OU
Sulfur Species (Vppra ± 2a)
H2S
COS
SO 2
CS2
Total volatile sulfur
Ci-C$ Hydrocarbons (Vpptn ± 2o)
CH.,
C2H6
C2Hu
CB + isomers
Ci* + isomers
Cs + isomers
C6 + isomers
Nitrogen Species (Vppm ± 2o)
NH3
HCN
Metal Carbonyls (Vpom)
Fe(CO)5
Ni(CO)i,
Product
9.5
15.4
0.7
46.8
26.3
1.3
1110
143
16
12
990
9590
643
314
445
193
202
197
842
200
NR
Gas
± 1.8
± 2,4
± 0.4
± 4.1
± 4.6
± 0.3
± 130
± 16
± 50
± 4
± 1510
± 132
± 68
± 68
± 42
± 392
± 100
± 943
± 90
NR Not Reported
E-40
-------
TABLE E-31,
TRACE AND MINOR ELEME-NIxCOMPOSITIONS OF
LOW BTU PRODUCT GAS {*''
Element
Aluminum
Antimony
Arsenic
Barium
Beryllium
Bismuth
Boron
Bromine
Cadmium
Calcium
Cerium
Cesium
Chlorine
Chromium
Cobalt
Copper
Dysprosium
Erbium
Europium
Fluorine
Gadolinium
Gallium
Germanium
Gold
Hafnium
Holmium
Iodine
Iridium
Iron
PRODUCT
Participate
ug/SCM
27,000
<380
370
7,600
2.6
2.6
550
130
270
150,000
51
2.3
>3,200
88
14
270
1.7
0.64
0.97
1,300
1.9
23
7.2
2.9
0.97
<4
<33,000
GAS
Vapor
yg/SCM
0.42
<16
>18
21
>13
0.88
460
0.88
16
15
>0.8
11
9.2
13
460
Total
ug/SCM
27,000
<400
>390
7,600
2.6
2.6
>560
130
270
150,000
53
2.3
>3,200
100
>15
280
1.7
0.64
0.97
1,300
1.9
36
7.2
2.9
0.97
-------
TABLE E-31 (CONTINUED)
Element
Lanthanum
Lead
Lithium
Magnesium
Manganese
Mercury
Molybdenum
Neodymium
Nickel
Niobium
Phosphorus
Platinum
Potassium
Praseodymium
Rhenium
Rubidium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Sulfur
Product
Participate
yg/SCM
36
130
120
39,000
120
6,500
9.7
9.7
110
13
>3,200
>3,200
6.4
<0.3
<7
6.4
19
15,000
>6,700
110
21,000
3,900
>3,500
Gas
Vapor
yg/SCM
1.3
29
6.3
25
7.1
3.3
9.6
94
69
2.0
>3
330
30
31
4.2
860
Total
yg/SCM
37
160
130
39,000
130
6,500
9.7
9.7
120
13
>3,300
>3,300
6.4
<0.3
<9
6.4
19
15,000
>7,000
140
21,000
3,900
>4,300
E-42
-------
TABLE E-32.
ORGANIC COMPOUNDS IDENTIFIED FROM THE PRODUCT GAS
BY SIM GC/MS ^ }
Compound Identified
Concentration4
yg/SCM
Sample
LC Fraction
Polychlorinated biphenyls^
Benzo(a)anthracene
Benzo(b) f 1 uoranthene
Biphenyl
7, 12-Dime thy lbenzo( a) anthracene
Benzo(c)phenanthrene
Benzo(a)pyrene
3-flethyl chloranthrene
Dibenzo( a, h) anthracene
Dinitrotoluenes
Dinitrocresol
Dihydroacridine
<15.0
1.8E3b
3.8E2b
5.1E3
1.6E2b
1.0E3b
1.9E2
4.7
6.1
2.2E3
1.8E3
1.1 E2
PGP-2
PGP-2
PGP-2
PGP-3
PGP-3
PGP-3
PGP-3
PGP-3
PGP-3
PGP-4
PGP-5
PGP-5
; PGC-2
,3; PGC-2, 3
,3; PGC-3
; PGC-3
; PGC-3
; PGC-5
,6
SCM at 25°C (77°F) and 101 kPa (1 atm), dry basis
PGP = product gas particulate
PGC product gas organic module composite
a aEb a x 10b
includes possible coeluting isomers
c based on PCG-3 Cl
standard unavailable, based on dihydrophenanthridine
E-43
-------
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of Parahoe Crude Shale Oil Into Military Specification Oils,"
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San Diego, August 1973.
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Modifications. EPA-600/7-78-099a, June 1978.
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Analytical Chemistry, 46:239, February 1974.
13. Vitez, B. "Trace Elements in Flue Gases and Air Quality
Criteria," Power Engineering, pp 56-60, January 1976.
E-44
-------
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graphy Separation of Olefin, Saturated, and Aromatic Hydrocarbons
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Utah Shale Oils." Proceedings of the 12th Oil Shale Symposium.
Golden, Colorado: Colorado School of Mines, 1979.
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York: McGraw-Hill , 1968.
17. Robinson, E.T. Refining of Paraho Shale Oil into Miltary Speci-
fication Fuels. Proceedings of the 12th Oil Shale Symposium.
Golden, Colorado: Colorado School of Mines, 1979.
18. Sullivan, R.F. Refining and Upgrading Synfuel from Coal and Oil
Shales by Advanced Catalytic Processes. Chevron Research Company
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19. Sullivan, R.F., B.E. Stangeland and H.A. Frumkin. "Refining the
Products from the SRC Coal Liquefaction Process," Proceedings of
the American Petroleum Institute Refining Department, 1979.
20. Sullivan, R. F., D. J. O'Rear, and B. E. Stangeland. "Catalytic
Hydroprocessing of SRC II and H-Coal Syncrudes for BTX Feed-
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21. Riedl, F. J. and A.J. de Rosset. "Hydretreating and Reforming
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Interim Report, UOP, Inc., FE-2566-27, June 1979a.
22. Gim, Tan and A.J. de Rosset. "Hydrotreating and Reforming Exxon
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Liquids, Interim Report, UOP, Inc. FE-2566-25, February 1979.
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24. Gim, Tan and A.J. de Rosset. "Hydrotreating and Fluid Catelytic
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Liquids, Interim Report. UOP, Inc. FE-2566-20, August 1978b.
E-45
-------
25. Gim, Tan and A.J. de Rosset. "Hydrocracking of H-coal Process
Derived Gas Oils," Upgradin
FE-2566-23, November i978c.
Derived Gas Oils," Upgrading of Coal Liquids, Interim Report.
~T<
26. Saunders, W.N. and J.B. Maynard. "Capillary Gas Chromatographic
Method for Determining the C^ - C1? Hydrocarbons in Full-Range
Motor Gasolines," Analytical Chemisty 40(3): 529 (1968).
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DE-AC01-79PE-70021, May, 1980.
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Philadelphia, PA.
29. Hazelton Laboratories America, Inc. "24-Month Inhalation
Toxicity Study of Raw and Spent Shale Dusts in Rats and Monkeys,"
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30. Riedl, F.J. and A.J. de Rosset. "Hydrocracking of EDS Process
Derived Gas Oils," Upgrading of Coal Liquids, Interim Report.
UOP, Inc., FE-2566-33, November 1979c.
31. Hoogendorn, J.C. "Experience With Fischer-Tropsch Synthesis at
SASOL." Presented at Institute for Gas Technology, Chicago,
Illinois 1973.
32. American Society for Testing and Materials. ASTM Method
0-396-75. Philadelphia, PA.
33. O'Rear, D.J., R.F. Sullivan, and B.E. Stangeland. "Catalytic
Upgrading of H-Coal Syncrudes." Proceedings of the National ACS,
Houston, Texas, March 1980.
34. Schreiner, Max. "Research Guidance Studies to Assess Gasoline
from Coal By Methanol-to-Gasoline and SASOL-Type Fischer-Tropsch
Technologies." Prepared by Mobil Research and Development
Corporation for the U.S. Department of Energy, FE 2447-13, August
1978.
35. Shelton E. "Motor Gasolines Winter 1978-79." Bartlesville
Energy Technology Center, U.S. Department of Energy,
BETC/PPS-79/3 July 1979.
36. Forney, A.J., W.P. Haynes, et al. "Analyses of Tars, Chars and
Water Found in Effluents from the Synthane Process." Pittsburgh
Energy Research Center, Pittsburgh, PA. Technical Progress
Report 76, January 1974.
E-46
-------
37. Ghassemi, M., K. Crawford and S. Quivlivan. "Environmental
Assessment Report: Lurgi Coal Gasification Systems for SNG."
Prepared by TRW Inc. for U.S. EPA Industrial Environmental
Research Laboratory, Research Triangle Park, N.C.,
EPA-600/7-79-120, May 1979.
38. Westfield Development Center. Data provided to EPA's Industrial
Environmental Research Laboratory, Research Triangle Park, No.
Carolina, Novemver 1974.
39. South Africa Coal Oil and Gas Corp., Ltd. Table based on data
provided to EPA's Industrial Environmental Research Laboratory,
Research Triangle Park, November 1974.
40. Liederman, D. et al. "Mobil Methanol-To-Gasoline Process,"
Proceedings of the 15th Intersociety Energy Conversion
Engineering Conference. Seattle, Washington, August 18-22, 1980.
41. "Mobil Proves Gasoline-From-Methanol Process," Chemical and
Engineeirng News. January 30, 1978.
42. Timourian, H. and F. Milanovich. "Methanol as a Transportation
Fuel: Assessment of Environmental and Health Research." UCRL
52697, Lawrence Livermore Laboratory, Livermore, California,
1979.
43. Kuo, James, C.W. and M. Schreiner. "Status of the Mobil Process
for Converting Methanol to High Quality Gasoline." Proceedings
of Fifth Annual International Conference on Commercialization of
Coal Gasification, Liquefaction and Conversion to Electricity.
University of Pittsburgh, PA., August 1-3, 1979.
44. Badger Plants, Inc. "Conceptual Design of a Coal-to-Methanol-
to-Gasoline Commercial Plant." Second Interim Final Report for
the Period August 31, 1977 March 1, 1979. Volume I,
FE-2416-43, March 1979.
45. C.F. Braun and Company. "Carbonyl Formation in Coal Gasification
Plants." Prepared for the U.S. Energy Research and Development
Administration and the American Gas Association, FE-2240-16,
December, 1974.
46. U.S. Bureau of Reclanation. "Final EIS: Proposed Western
Gasification Company (WESCO) Coal Gasification and Expansion of
Navajo Mine by Utah International, Inc., U.S. Department of
Interior, 1976.
47. Kilpatrick, M.P. et al. "Environmental Assessment: Source Test
and Evaluation Report; Wellman-Galusha (Ft. Snelling) Low-Btu
Gasification." EPA-600/7-80-097, U.S. Environmental Protection
Agency, Washington, D.C., May 1980.
E-47
-------
48. Wigg, E.E. "Methanol as a Gasoline Extender: A Critique."
Science 186 (4166): 785, 1974.
E-48
-------
APPENDIX F
COMBUSTION PRODUCTS AND USE PROPERTIES
OF SYNTHETIC FUELS
TABLE OF CONTENTS
Page
F.I COMBUSTION OF SHALE OIL PRODUCTS F-3
F.I.I Crude Shale Oil F-3
F.I.2 Gasoline From Shale Oil F-9
F.I.3 Shale Oil Jet Fuels F-9
F.I.4 Diesel Fuel Marine F-9
F.2 DIRECT LIQUEFACTION PRODUCTS USE/COMBUSTION TESTING ... F-10
F.2.1 SRC II Fuel Oil Testing F-10
F.2.2 H-Coal Distillate Combustion Tests F-20
F.2.3 Combustion/Handling Properties of EDS Coal
Liquids F-23
F.3 CHEMICAL CHARACTERIZATION OF INDIRECT COAL LIQUIDS
COMBUSTION PRODUCTS F-28
F.4 CHEMICAL CHARACTERIZATION OF LOW-/MEDIUM-BTU COAL GAS
COMBUSTION PRODUCTS F-28
F-l
-------
TABLES
Number Page
F-l PROPERTIES OF PARAHO CRUDE VS. LOW SULFUR OIL . . F- 3
F-2 EXCESS NO FROM SHALE OIL COMBUSTION TESTS
COMPARED TO BASELINE LOW SULFUR OIL F-4
F-3 PNA EMISSIONS SHALE OIL TESTS F-8
F-4 SRC II FUEL OIL COMBUSTION RESEARCH PROJECT
EQUIPMENT, CONDITIONS, AND EMISSION RESULTS. ... F-11
F-5 PHYSICAL HANDLING PROPERTIES OF SRC FUEL OIL
VERSUS PETROLEUM DISTILLATES F-13
F-6 NO VALUES FOR SRC II, NO. 2 AND NO. 5 FUEL OIL
UNDER VARIOUS CONDITIONS (ppm) F-15
F-7 ASH ANALYSES-SRC FUEL OIL AND NO. 5 FUEL OIL ... F-16
F-8 AVERAGE FUEL PROPERTIES F-18
F-9 COMPARISON OF SHALE OIL, SRC II, AND TYPICAL
PETROLEUM FUELS AND COMBUSTION EMISSIONS (ug/m). . F-21
F-10 EDS FUEL OIL COMBUSTION TEST PARTICULATE
AND NO EMISSIONS F-25
^
F-ll PROPERTIES OF EDS FUEL OILS F- 27
F-12 GASEOUS SPECIES ANALYSIS SUMMARY: LOW-BTU
TEST BURNER FLUE GAS F- 29
F-13 TRACE AND MINOR ELEMENT COMPOSITIONS
OF LOW-BTU TEST BURNER FLUE GAS F-30
FIGURES
Number Page
F-l MASS EMISSION RESULTS F-5
F-2 PARTICLE SIZE DISTRIBUTION F-6
F-3 PARTICULATE EMISSIONS SUMMARY F-19
F-4 RELATIVE NO VALUES AS A FUNCTION OF THE FUEL-BOUND
NITROGEN CONTENT OF THE H-COAL FUELS F-22
F-2
-------
F.I COMBUSTION OF SHALE OIL PRODUCTS
A large amount of work has been and is being conducted by the DOD on
the combustion properties of shale oil derived products. Most of the work
reported to date is based on the tests of a 10,000 barrel sample of shale
oil that was produced at Anvil Points, Colorado by the Paraho process. It
was refined into synthetic gasoline, JP-4, JP-5, diesel fuel marine (DFM),
and heavy fuel oil at the Gary Western refinery. In addition to the DOD
efforts, Southern California Edison Company (SCE) studied the handling and
combustion of a separate lot of Paraho crude shale oil for EPRI. The main
test results of these projects are presented, by product, in the following
sections.
F.I.I CRUDE SHALE OIL
The composition of the crude Paraho shale oil used during a series of
combustion tests (Reference 1) at the SCE Highgrove Generating Station is
compared in Table F-l to the low sulfur oil normally burned.
TABLE F-l. PROPERTIES OF PARAHO CRUDE VS. LOW SULFUR OIL
Elemental Analysis (wt %)
Ash
API
C
H
N
S
0
Content
Gravity @ 60°F
Paraho Oil Shale
86.05
11.48
1.98
0.68
1.81
0.222
20.3
Low Sulfur Oil
86.38
12.49
0.22
0.27
0.64
0.009
24.6
Heating Value
HHV 18,195 19,235
LHV 17,145 18,100
The Highgrove Unit 4 is a balanced draft 45 MW Combustion Engineering
boiler. Mass loading, NO , and particle measurements were taken during
both the baseline and lowxNO mode runs.
/\
The shale oil NO levels were consistently higher than the low sulfur
oil NO levels. Because of California air quality standards, only 50
percent of the fuel feed or 50 percent of the burners were fueled by the
shale oil. The calculated excess NO added by the shale oil is given in
Table F-2. The increase in NO is attributed to the higher N content of
the shale oil, and would be above current federal standards. The
F-3
-------
combustion modification tests conducted by SCE did show promise of reducing
the shale oil NO emissions. Further tests are necessary to optimize those
procedures.
TABLE F-2. EXCESS NO a FROM SHALE OIL COMBUSTION TESTS
A
COMPARED TO BASELINE LOW SULFUR OIL
% Shale Oil
Combusted Normal Firing Off Stoichiometric Firing,
(Approx) ppm ppm
10
20
30
40
50
+93b
+ 134
+ 170
+206
+224
(+166)C
(+282)
(+368)
(+446)
(+548)
+72b
+99
+ 138
+186
+209
(+94)C
(+141)
(+178)
(+206)
(+225)
Baseline emission
for low sulfur oil 216 (248) 222 (225)
a. Corrected to 3% 02
b. Low NO burner
^
c. Peabody burner
The mass emission results from the SCE tests are displayed in Figure
F-l. The mass emissions during the shale oil tests were much higher than
with the low sulfur oil. It was postulated (Reference 1) that as the
individual fuel droplets burned, surrounded by their own diffusion flame,
fuel cracking occurred in the liquid phase within the drop. The cracking
proceeded at a rate proportional to fuel boiling temperature, producing
initially heavy fuel residue. The residue in turn increases theoverall
boiling temperature of the fuel blends within the drop, allowing fuel
cracking to proceed at a faster rate. Further cracking finally produces
carbonaceous and char-like particulates, which are left after droplet
combustion is completed.
This mechanism would also explain why most of the particles emitted
were larger than 10 u m. Figure F-2 displays the particle size measurement
results from the SCE lists and compares them to a typical oil fired
(Reference 2) result. The production of large particles during oil firing
is not the normal case, as estimates of particle size distributions from
oil fired boilers range from 58 weight percent below 3 urn (Reference 3) to
F-4
-------
0.20
0.15
w
PQ
CO
§
§ o.ia
O.U50
O.C1C
All Points
-3,
y-(2.6xlO J)xlOO
0.51
A'Tanic Blended
.Dual Burner
'"Blending
Low Sulfur
""Oil Alone
10
20 30 40
% SHALE OIL BLENDING
50
Figure F-l. Mass Emission Results
F-5
-------
100
48.6% Tank Blendec
Shale Oil (1)
49.7% Dual Burner
Bleeding (1)
Power
Plant (2)
0.1
1. SCE/EPRI
?. Bennet
100
PARTICLE SIZE (urn)
Figure F-2. Particle Size Distribution
F-6
-------
90 weight percent below 7 m (Reference 4). The larger particles produced
by the shale oil would pose no removal problem and, in fact, could be less
of a health problem because of less penetration into the respiratory tract.
Data on the trace element emissions from the boiler were not given,
but the trace element composition of the shale oil burned was measured.
Comparing it to the data in Table E-3 in Appendix E, only arsenic, boron,
manganese, and mercury appear in higher concentration than in residual or
crude oils. Of the group, only arsenic was present in significantly higher
amounts (9.4 ppm vs. 0.17 ppm for crudes).
The final parameter studied was the polynuclear aromatic (PNA)
emissions from the boiler during the burning of an approximate 50/50 shale
oil/low sulfur oil mixture (Table F-3). Comparing the total amount o^
PNA's found at five other petroleum oil burning plants, the 0.92 ug/m from
the shale oil tests was at the low end of the concentration range (0.1 to
2.3 Mg/m3). During the SCE tests, only the filter was analyzed, and no
mention was made of using XAD-2 or other absorbents to quantitively collect
PNA's that might be present in the vapor phase. Depending on stack
temperature and sampling conditions, the actual PNA value could be higher.
As result of this study it can be concluded that:
• No significant fuel handling, fuel mixing, combustion
instability, smoke formation, or boiler operational problems
occurred during the burning of shale oil.
• NO emissions, on the average, were 90 to 500 ppm higher during
normal burning and 70 to 225 ppm higher during off-stoichiometric
burning.
• Conventional off-stoichiometric combustion techniques reduced NO
emissions. x
• Particulate emissions were greater than those produced during oil
fi ring.
• The particle size distribution showed that 90 percent of the
particles were larger than 20 ym.
A study (Reference 5) of the combustion characteristics of whole,
de-ashed and desulfunzed Paraho shale oil was conducted on a subscale gas
turoine-like combustor. The nitrogen content ranged from 0.33 to 1.63
percent for the desulfunzed sample. The excess NOX values were 60 to 180
ppm higher than the No. 2 fuel oil baseline data over the range of fuel-
bound nitrogen and the exhaust temperatures studied. Smoke values were
slightly above the values for No. 2 distillates over most of the range of
exhaust temperatures tested.
F-7
-------
I
00
Compound
Naphthalene
Phenanthridine
Dlbenzothiophene
Anthracene/Phenathrene
Fluoranthene
Pyrene
Chrysene/benz(a)anthracene
Benzopyrene and perylenes
Benzo(a)pyrene
Benzo(e)pyrene
Benzo(g,h,i) Perylene
Benzo Fluoranthenes
Methyl Anthracene
Total
AVERAGE
Shale Oil/
Crude Oil m,
Utility Boiler u;a
._
--
--
--
0.4>>
0.15
0.12
0.23
-
0.92
a 49.3% shale oil, 50.7% low sulfur crude
b Benz(a)anthracene
c Range from 3 plants, filter sample
d) XAD-2 resin sample
CONCENTRATION (ug/m3)
Oil-Fired ,«».
utility Boiler^'0
5
0.3
0.6
0.6
1
1
0.1
0.04
-
-
-
9.24
Oil-Fired m Oil-Fired ...
Utility BoilerlJ'c Utility Boiler^'0
-
-
-
0.008-2.13 0.024
0.007-0.098 0.009
0.006-0.051 0.0004
0.00019
0.032
0.032
0.00005
<0.1-0.21
0.021-2.28 0.10
—(
co
m
-n
00
•sc.
3
(— 1
oo
o
00
1
oo
DC
r*
m
o
00
—t
oo
-------
These subscale tests were followed by full scale tests (Reference 8)
with the same Westinghouse combustor used in their 35- and 90-MW engines.
Whole Paraho shale oil was burned and the results for NOX and smoke were
compared to No.2 petroleum distillate. The N0x levels for the shale oil
(nitrogen 0.33 percent) were 10 to 20 ppm higher, with the lowest NOX level
reached at the highest (2000 F) exhaust temperatures. The shale oil
produced the highest smoke levels of the synfuels tested (H-Coal and SRC II
blend). Overall, it was concluded that the shale oil produced no
significant differences in combustion characteristics compared to petroleum
diesel fuels.
F.I.2 GASOLINE FROM SHALE OIL
The Army Fuels and Lubricants Research Laboratory (AFLRL) has
performed limited tests with shale oil gasoline. The gasoline produced
from the Gary Western run failed the existent gum test (4 mg/100 ml versus
2mg/100 ml allowed), and early tests with an off-specification gasoline
produced severe exhaust valve erosion/corrosion. When the engine cycling
tests were repeated with a new lot of the shale oil gasoline, no problems
were encountered and no abnormal wear was found. No data on emissions were
presented.
F.I.3 SHALE OIL JET FUELS
Neither the JP-4 nor JP-5 fuels met the military specifications for
contamination or gum content. Both of these parameters can be controlled
at the refinery and will not be a problem in commercial products. Both
clay treatment and secondary hydrotreatment produced fuels of much higher
quality.
Combustion tests of JP-4 showed that it behaved the same as petroleum-
based JP-4 with the exception of NO emissions. JP-5 exhibited similar
problems with NO* (+15 to 20 ppm) and had a smoke number 12 times higher
than petroleum JP-5. This increase in the smoke number was attributed to
the higher aromatic content of the fuel. A flight test using JP-4 in a
T-39 was conducted. Performance was rated normal and no in-flight problems
were encountered.
F.I.4 DIESEL FUEL MARINE (DFM)
The shale oil DFM tested did not meet the military specifications for
viscosity, pour point, or acid number. Tests using a corrosimeter showed
no measured corrosion for aluminum or 70/30 copper/nickel alloy, and very
little for 90/10 copper/nickel (0.1 mil/yr), moderate corrosion of copper
(0.8 mil/yr) and mild steel (1.2 mil/yr), and relatively severe corrosion
of zinc (9.8 mil/yr). These levels were deemed acceptable and it was
expected that there would be no compatibility problems in ship fuel
systems.
Tests with typical diesel engines showed that combustion efficiency,
CO, and THC were the same as for petroleum DFM. The exhaust smoke was high
F-9
-------
and the NO values ranged from 20 to 60 ppm higher than in petroleum DFM
tests.
F.2 DIRECT LIQUEFACTION PRODUCTS USE/COMBUSTION TESTING
Most combustion testing of direct liquefaction products has been done
on the SRC II liquids. As Table F-4 (ORNL) shows, a variety of systems
have been used to evaluate their combustion properties. Only limited
studies on H-Coal (Reference 9) and EDS (Reference 10) liquids have been
completed. All the SRC II studies have been done on fuel-oil-type liquids.
Generally this implies that some ratio of middle to heavy distillates was
used in the test program. The ratio of middle to heavy distillates ranged
from 2:1 to 5.75:1 in the programs to date.
F.2.1 SRC II FUEL OIL TESTING
In one of the early tests (Reference 11), the factors affecting NO
production during the burning of SRC II fuel oil (4:1 MD to HD) were
studied. This work concluded that fuel surface tension, viscosity and
vaporization characteristics were important in determining the conversion
level of fuel-bound nitrogen to NOX. It was assumed that the proportions
in which the medium and heavy distillates of SRC II were blended may have
had a significant effect on the NO levels. While high proportions of the
heavy distillates would be desirable to provide delayed evaporation and
pyrolysis for the production of N0x-reducing radicals, such a high
concentration could lead to excessively high 0^ levels which may adversely
affect NO emission. On the other hand, larger proportions of SRC II
medium distillate may be tolerated and may result in an optimum NO
reduction and low excess 0- operation if mixing intensity and locaf fuel
stoichiometry within the burner flame controlled by appropriate burner
design. The SRC II blend proportions that are effective for NOX control in
the normal firing mode may not be effective in the off-stoichiometry mode.
Also, blend proportions for maximum NOX reduction may vary from boiler to
boiler, depending on burner design and furnace firing arrangement. It was
concluded that effective NO control can be achieved by designing special
burner hardware that would cielay mixing and would control the local fuel
stoichimetry within the fuel.
In another test (Reference 5) of the handling and combustion
properties of SRC II, a middle distillate, a heavy distillate, a middle/
heavy blend, a 3:1 No. 2 distillate-to-SRC II blend, and a 1:1 No.2
distillate-to-SRC II blend were evaluated on a subscale gas-turbine-like
combustor. In general, all the fuels burned well, and there were no
significant handling problems. It was found that the percent emissions of
fuel-bound nitrogen (FBN) decreased as FBN increased and as outlet
temperature increased. The maximum excess NO levels (SRC II heavy
distillate) ranged from 20 to 130 ppm above the baseline values of 30 to
130 ppm. Smoke levels increased with decreasing hydrogen content and
increasing aromaticity of the fuels.
F-10
-------
TABLE F-4.
SRC II FUEL OIL COMBUSTION RESEARCH PROJECT—EQUIPMENT,
CONDITIONS, AND EMISSION RESULTS (12)
Author
KVB (1979)
Con Ed
Babcock
& Wllcox
Ontario
Res. Found.
Southern
Calif.
Edison
Gulf
Science
Technology
Westing-
house
Pratt «
Whitney
Fuel .
(MO/HO) a
SRC II F.O.
(2/1)
SRC II F.O.
(5.75/1)
SRC ll F.O.
(5.75/1)
SRC II F.O.
(VI)
Various
Blends
Range of
Coal
Liquids
Doped
No. 2 oil
Equipment
boiler or
furnace
Package
boiler,
II
44-MW
field
boiler
Package
boiler
Vorto-
metrlc
burner 4-ft-
ID tunnel
Test
tunnel
3-ft-ID
Package
bol ler
Single
combustor
In duct
Single
combustor
Flame configuration for
emissions suppression
Fuel-rich burner, down-
stream 2 air Injector
Staging by fuel redistri-
bution to lower burners
and air redistribution
"Dual-register" burner,
separate control of b
Inner and outer air flows
VortometMc burner + 8-ft.
tunnel section fuel-rich;
2° air; 20-ft second-stage
tunnel
TRW/SCE burner, nonstagfng
Radial fuel jets
Conventional air-atomizing
burner, no staging; effect
of blends on unreduced
emissions
Conventional combustors
for stationary gas turbines,
subscale and full scale
Gas turbine combustor
low-NO design
Firing rate
(10° Btu/h)
(MW)
3
3
3
(44)
45
5
10
1
0.6
--
% Excess
air
overall
6
6
40
--
1-2
11
6.5
10-60
300-
400
300-
400
X
Total air
entering
first stage
60
50
d
50
d
d
100
75
NO ppm
Corrected to
15$ excess air
(lb/10° Btu)
225 (0.3)
320
780
175
400-
480
150
330
200-
600
160-
320
75e
Fuel NOC
yield
(X)
—
8-13
--
— —
22
20-60
40-95
--
Smoke Number
ASTM
(Ib particulates
per 10 Btu)
(0.2)
(o.i)d
( 0.03)
(0.02)
(150 ppm CO)
Acceptable
0.5-9
Various
Acceptable
aRat1o of SRC II middle distillate (MD) to heavy distrlllate (HD).
bDue to scaledown error, this unit functioned like a conventional B4W burner.
cThere was no second-stage air Injection downstream from burner.
dW1th combustion Improver additive.
Corrected to 15J 02 1n exhaust; at full load.
-------
In a later program (Reference 8), an SRC II blend {5:1 middle-to-heavy
distillates) was tested on a full-scale combustor used in the Westinghouse
30- and 90-MW engines. The SRC II blend with a FBN of 9.83 percent had NO
emissions 30 to 120 ppm higher than No.2 distillate over an outlet burner
temperature range of 1000 to 2000 F. Smoke values for the SRC II decreased
with increasing exhaust temperature, which is the opposite of No. 2
distillate. A major corrosion study (187.5 hours) using various alloys and
SRC II solvent wash showed that the SRC II wash solvent did not appear to
present a corrosion or deposit problem any more severe than petroleum-
derived fuels of similar properties. It was suggested, as with petroleum
fuels, that sodium, potassium, lead, and vanadium be controlled.
Extensive handling and combustion testing was conducted by Babcock and
Wilcox (Reference 13) using a package boiler and a 5.75:1 SRC II fuel oil.
The physical properties of the SRC II fuel oil are shown in Table F-5. The
SRC II is similar to No. 5 fuel oil in density, but in viscosity it behaves
more like No. 2 fuel oil. This characteristic made it easy to pump and
handle during the test program. The only handling precaution taken was to
replace all hydrocarbon seals with Teflon or Viton seals because of SRC
II's phenol/aromatic content. No handling problems were encountered with
these precautions. Ambient monitoring programs for benzene and phenols
emissions were negative.
The nitrogen content of the SRC II fuel oil was 0.8 percent compared
to 0.03 and 0.2 percent for No. 2 and No. 5 fuel oils, respectively.
Sulfur content of the SRC II fuel oil was essentially the same as for the
No. 2 fuel oil and substantially below thatt of the No. 5 fuel oil. The
NO levels measured under different conditions are summarized in Table F-6.
Inxall cases the NO levels were higher than for the No. 2 and No. 5 fuel
oils. However, Babcock and Wilcox concluded that because fuel/air mixing
seems to play such a significant role with SRC fuel oil, it would appear
that two-stage combustion could effect satisfactory control and bring
emissions below EPA's new allowable limit of 0.5 pound NOx/MBtu heat input
for coal liquids.
Also, in spite of its high aromaticity, the SRC II fuel oil showed no
tendency to smoke during combustion testing. In fact, particulate
emissions from SRC fuel oil combustion were less than from No. 5 fuel oil
combustion. Table F-7 compares the elemental analysis of ash from SRC II
and from No. 5 fuel oils. Recalling that the SRC II had an ash content of
0.014 percent versus the 0.025 percent from No. 5 fuel oil, the elemental
composition of SRC II fuel would be generally lower than the No. 5 fuel oil
except for Fe, Ca, Mg, K, Cr, and Sn.
The most extensive testing to date of an SRC II fuel oil was done by
KVB (Reference 14) at a Consolidated Edison 44-MW field boiler. The
•average SRC II fuel oil compositon compared to No. 6 fuel oil is shown in
Table F-8. No major boiler operational problems were caused by the
combustion of SRC II fuel oil. The optimization of burner hardware for SRC
II fuel oil firing was not considered to be any more stringent than would
F-12
-------
TABLE F-5. PHYSICAL HANDLING PROPERTIES OF SRC FUEL OIL VERSUS PETROLEUM DISTILLATES^3^
I
t—•
GO
Parameter
Density
API 0 77°F
API 0 6Q°F
S.G. 0 67°F
Viscosity - Saybolt
Universal Seconds
0 77°F
0 80° F
0 122°F
0 145°F
0 174°F
0 204°F
Pour Point, °F
Sediment by
Toluene Extraction, %
Sediment and Water
(ASTM D96-73)
SRC Fuel Oil3
12.4
11.5
0.9895
47.7
37.0
34.4
Below -35°
0.05
1.0
No. 2 Fuel Oil
40.3
39.0
0.8299
36.3
32.4
32.0
-20°
None
None
No. 5 Fuel Oil
16.0
15.1
0.9652
267
143
91
67.2
Zero0
0.10
1.9
a Ratio of 5.75:1 Middle to Heavy Distillates
(continued)
-------
TABLE F-5. (CONTINUED)
Parameter
SRC Fuel Oil9
No. 2 Fuel Oil
No. 5 Fuel Oil
Miscibility
% SRC in
% No. 2 in
% No. 2 and
No. 5 Mixture in
Copper Corrosion
(ASTM D130-75)
Surface Tension,
dynes/cm @ 22°C
Oxidation Stability
mg/100 ml
(ASTM D2274)
Totally
Miscible
Moderate, 2b-
Color: Lavender
34.1
4.0
Totally
Miscible
Slight, Ib-
Color: Dark Orange
29.9
10.7
Totally
Miscible
Totally
Miscible
Moderate, 2c-
Color: Multicolored
34.5
a Ratio of 5.75:1 Middle to heavy Distillates
-------
TABLE F-6. NO VALUES FOR SRC II, NO. 2 AND NO. 5
FUEt OILS UNDER VARIOUS CONDITIONS (PPM)
Fuel
SRC II
No. 5
No. 2
Fuel
Bound N
475
225
100
Atomizer Burner
Design Design Load
410-610 400-600 360-475a
200-225 100-225
3 at 3% 02
be required to accommodate similar changes tor petroleum fuels. Boiler
thermal efficiency levels were comparable to those obtained with No. 6 fuel
oil. No adverse deposits were observed in the internal boiler either
during the tests or in the post-combustion inspection.
Nitrogen oxide emissions were nominally 70 percent greater than those
obtained from the No. 6 fuel oil under both baseline and low NO
conditions. Assuming equivalent thermal NO formation, this implies a 10
percent conversion of the differential fuel nitrogen to NO conditions.
Reductions in NO through staged combustion were on the oraer of 35 percent
for both SRC II and No. 6 fuel oils. It would be expected that a boiler
currently capable of satisfying the EPA New Source Performance Standards
(NSPS) for NOx emissions of 0.3 Ib/MBtu would be capable of satisfying the
proposed 0.5 Ib/MBtu NSPS for coal-derived liquids using an SRC II fuel oil
equivalent to that burned in this test program.
Particulate mass emissions were nominally lower for SRC II fuel oil
than for the No. 6 fuel oil and were below the EPA proposed New Source
Performance Standards of 0.03 Ib/MBtu under all test conditions (Figure
F-3). The emissions at full load exhibited a bi-model size distribution
composed of a large number of carbon particles with diameters on the order
of 0.05 micron or less and a smaller number of agglomerated particles
larger than 0.1 micron. The No. 6 fuel oil emissions did not exhibit this
agglomerated behavior although the actual particle concentrations were
higher than for the SRC II fuel oil. No mechanism was determined for the
observed agglomeration, which was substantially reduced at lower boiler
loads. The No. 6 fuel oil emissions contained a number of large particles
(greater than 1 micron), indicative of an atomization-related formation
mechanism. Such particles were not observed with the SRC II fuel oil,
indicating potentially better atomization characteristics even though the
actual atomizer components were not optimum for this fuel.
The PNA emission levels with both fuel oils were low-less than (6 x
10-6 Ib/MBtu). Trends indicated by the PNA data, although qualified by the
overall test uncertainty, indicated that emissions at half load were higher
than those for full load with both fuels. The data also indicated that the
F-15
-------
TABLE F-7. ASH ANALYSES - SRC FUEL OIL AND NO. 5 FUEL OIL
Sample No.
Sample Description
Spectrographic
Analysis, %c
Silicon as Si02
Aluminum as A1203
Iron as Fe000
c. o
Titanium as TiOo
Calcium as CaO
Magnesium as MgO
Sodium as Na90d
t .
Potassium as K/,0
Nickel as NiO
Chromium as CrgOj
Molybdenum as MoO-j
Vandium as V205
Cobalt as CoO
Manganese as Mn02
F-1442
SRC Fuel
Middile &
Semi-Quantitative
29.5
30.0
18.5
0.7
5.5
1.3
1.75
1.35
0.5
2.6
0.1
0.5
0.06
0.4
Ash From
Oil Sample #1199
Heavy Distillate3
Quantitative
Major Constituent
29.5
27.0
19.0
0.9
4.5
1.2
1.75
1.35
—
—
—
—
F-1444
Ash From
No. 5 Heavy Fuel
Oil, B&W-ARC
(4/7/78) b
Semi -Quantitative
48.2
29.0
7.5
0.7
2.0
0.6
5.73
0.24
2.7
0.4
<0.06
7.8
(Quantitative)
0.06
0.06
(continued)
-------
TABLE F-7. (CONTINUED)
Sample No.
F-1442
F-1444
Sample Description
Ash From
SRC Fuel Oil Sample #1199
Middle & Heavy Distillate9
Ash From
No. 5 Heavy Fuel
Oil, B&W-ARC
(4/7/78)b
Spectrographic
Analysis, %c
Copper as CuO
Zinc as ZnO
Lead as PbO
Tin as SnOp
Zirconium as ZrO,
Sulfur as S03e
Semi-Quanti tati ve
<0.1
<0.3
0.06
0.2
0.06
Quantitative
Major Constituent
6.1
Semi-Qua'iti tati ve
0.2
<0.3
0.5
0.06
0.06
2.9
a. Ash content 0.014% in flue oil
b. Ash content 0.025% in fuel oil
c. The elements are reported as the oxides because of the analysis
method used. This does not imply their presence as such.
d. By Flame Photometer
e. Wet Chemical
-------
TABLE F-8. AVERAGE FUEL PROPERTIES
113)
Parameter
API Gravity at 60°F
H20 % by Volume
Sulfur % by Weight
Carbon % by Weight
Hydrogen % by Weight
Nitrogen % by Weight
Oxygen % by Weight
Heating Value (Btu/lb)
Ash % by Weight
Viscosity (sec. )
No. 6 Fuel Oil
25.0
0.20
0.24
87.02
12.49
0.23
--
19,200
0.02
SRC II Fuel Oil6
11.0
0.28
0.22
85.50
8.86
1.02
4.38
17,081
0.02
Saybolt Universal at 100°F 40
Viscosity (sec.)
Saybolt Universal at 122°F 300 700
Pour Point (°F-) 95 -30
Flash Point (°F) >200 150
Note: Because of sulfur content limitations in New York City,
the No. 6 oil utilized by Con Edison exhibits properties
close to a No. 5 residual oil.
a SRC II 5.75:1 Middle to Heavy distillate ratio
F-18
-------
H 0.05 +
Half Loaa
[ H Rema in ing
Carbon
S04
No Species 0.031
SRC n No. 5 SRC II No. 6
Baseline Low NOX
(8 Burner)
SRC n No. 6 SRC II No. 6 SRC H No. &
Low NOx Baseline Low NOx
(6 Burner)
FIGURE F-3. Particulate Emissions
F-19
-------
PNA emissions with SRC II fuel oil were nominally higher than those from
the No. 5 fuel oil levels. All PNA emission levels with both fuels were
substantially lower than those obtained on other programs (Reference 15)
with coal-fired boilers. Compared to the shale oil and oil-fired tests
(Table F-9), the values for the SRC II tests do not appear to be high.
Because of the limited number of PNA samples and uncertainties in the
combined sampling/extraction/analysis techniques, the absolute values of
PNA emissions obtained must be interpreted with caution.
Carbon monoxide levels were maintained below 50 ppmv for all test
conditions at generally equivalent total excess air levels for both fuels.
Thus, the SRC II fuel oil used in this program did not indicate any greater
tendency toward incomplete combustion than the existing No. 6 fuel oil.
F.2.2 H-COAL DISTILLATE COMBUSTION TESTS
Raw and hydrotreated H-coal distillate were tested (Reference 9) in a
combustion turbine, modified to accept small quantities of liquid (1 to 2
gallons per hour). The hydrogen contents in the liquids tested range from
9.8 to 11.8 weight percent, and the nitrogen contents ranged from 0.38 to
0.04 weight percent. A petroleum-derived No. 2 fuel oil was used as a
reference. The evaluations included fuel atomization, coke formation,
combustion parameters, and emissions.
The H-Coal fuel tested was readily forwarded and atomized with no
evidence of incompatibility with the No. 2 oil used for startup. There was
no problem with deposits in fuel lines, and the fuel had excellent
atomizing characteristics. This test did not indicate that the lighter
fractions contained in the fuels may vaporize more readily than the bulk of
the fuel, creating fuel-rich pockets of gas in the nozzle, and thus
contribute to a coking problem. The test results did demonstrate that coke
formation depended on the amount of hydrotreating. Increased hydrotreating
reduced the coke formation to negligible levels. Coke formation would be a
serious consideration in the utilization of all but the most severely
hydroprocessed of the coal liquids. This tendency will have to be
considered in both the selection of combustor modifications and the degree
of fuel upgrading required.
The ratio of NO measured with H-Coal liquids to the baseline NO
measured from No. 2 fuel oil combustion is plotted in Figure F-4 as a
function of the nitrogen content of the fuel. Note that the N0x values
observed (134 ppm) for the severely hydrotreated H-Coal distillate (10.5
and 11.7 weight percent H) were lower than or equivalent to those for No. 2
fuel oil (148 ppm), even though the coal liquids had a slightly higher
nitrogen content. In these cases the contribution due to fuel-bound
nitrogen has compensated for the reduced thermal NOX production rate. This
is in agreement with the lower exhaust temperatures observed for H-Coal
fuels compared to No. 2 fuel oil.
The level of CO observed in each of the tests was sufficiently low (31
to 41 ppm) and consistent to conclude that CO would not be a concern. The
F-20
-------
TABLE F-9.
COMPARISON OF SHALE OIL, SRC II AND TYPICAL PETROLEUM
FUELS AND COMBUSTION EMISSIONS (yg/m3)
I
ro
PETROLEUM FUEL OIL AND SHALE OIL
Chemical
Compound
Naphthalene
Phenanthrldine
Olbenzothlophene
Anthracene/ Phena threne
Fluoranthene
Pyrene
Chysene/benz (a) anthracene
Benzopyrene/Perylenes
Benzo (a) pyrene
Benzo (e) pyrene
Benzo (g.h.i) Perylene
Benzo fluoranthenes
Methyl Anthracenes/Phenathrenes
Benzo (c) Phenanthrene
Methyl Chrysenes
7,12 Demethylbenz(d) anthracene
Benzo(a) pyrene/Benzo(e) Pyrene
Indlno (1,2,3-cd) pyrene
TOTAL
u>
•O
~
•ad
,t >,
U.-T-
O=J
5
0.3
0.6
0.6
1
1
0.1
0.04
9.24
(N
(J^
Ol
IS
U. f-
0 =
0.008 - 2.13
0.007 - 0.098
0.006 - 0.051
«0.1 -0.21
<0.1 - 2.49
^
TJ^
^
•D m
1- >>
U. r-
o =>
0.024
0.009
0.0004
0.00019
0.032
0.032
0.00005
0.10
H
a. «"
"O
3 0)
U t—
o •»-
-^ o
*— T3 CO
O 1- >*
ailZi-
IQ r- •*-
.C ••- +*
t/)O 3
0.42(b>
0.15
0.12
0.23
0.92
SRC II AHO NO. 6 FUEL OIL
~ •sr
o *~l
•j; a)
K O
— O -J
— z
<-> X ^
a: o 3
4/1 _J U-
2.2 - 3.09
0.48 - 0.50
0.30 - 0.38
0.50 - 0.70
<0.003 - O.Ol'2'
0.03 - 0.17
0.1 - 0.2
0.48 - 1.03
0.02 - 0.08
0.10
0.010
0.02 - 0.06
0.11 - 0.18
4.83 - 6.03
_
o _ .
1*
"oj •""*
3 ^
C O
i "a! >«-
U> Wl f~
in S i
2.82
0.68
0.58
0.97
0.019(9)
0.15
0.19
2.14
0.12
0.39
0.060
0.05
0.039
8.21
f_
o
^ ^
"a> H
3 U
~-5 °
T'S ^
0 u< ^
ee « 3
Ul CO U-
1.63
0.41
0.16
0.24
0.008(g)
0.041
0.082
0.49
0.016
0.041
0.008
0.008
0.057
3.19
o
1 -o
3 A
t*. KO
O —I
XI Z
• X ^
O O 3
1.13
0.43
0.35
0.43
o.oog'9'
0.052
0.09
0.35
0.0009
0.09
0.009
0.009
0.052
3.01
o
0 T>
3 10
U- XO
O —I
~~ <^
- % *—
S3S
i.37
0.88
0.49
0.78
0.01
0.059
0.098
0.59
<0.003
0.098
<0.003
0.0)
<0.003
1.39
(a) 49.3% Shale 011, 50. 7X Low Sulfur Crude
(b) Ben 2 (a) anthracene
!c) Range from 3 plants, filter sampling only
d) XAO-2 Resin Sampling
(e) Two runs listed - Low NOX Burner
(f) Methyl Anthracenes
(g) Perylenes
-------
-o
•r—
3
CT
CU
1.4
1.3
1 .2
1.1
i.o-f-
0.9
0.8
Raw "-Coal Distillate (9.1 Wt % H)
Mildly HDT H-Coal Distillate (10.5 Wt £ H)
Severely HDT H-Coal Distillate (11.7 Wt "J K)
4-
.1 .2 .3 .4 .5
Fuel-Bound Nitrogen, Wt %
.6
Figure F-4. Relative NO Values as a Function of/the Fuel-Bound
Nitrogen Content of the H-Coal Fuels^ '
F-22
-------
unburned hydrocarbons (UHCs), however, did increase with the percent of
hydrogen in the fuel suggesting that improved wall cooling, which will be
required in a can-type combustor for coal liquids, may also return UHC to
more typical levels. Combustor designs incorporating hot ceramic walls
should be capable of particularly low levels of UHCs.
Available operating time was insufficient to establish the corrosion,
erosion, or deposition characteristics of each of the fuels. Because only
relatively low levels of alkali metals are present in the fuels, longer
periods of exposure are required before definitive data on the rate of
attack or deposition can be established. The trace alkali metals found in
the H-Coal liquids are not organically bound and can be removed by careful
distillation. The inorganic materials in the coal liquids are also
significantly reduced by hydroprocessing, presumably by deposition the
hydrotreating catalyst. This lowered nonhydrocarbon content should
contribute to a longer turbine life.
In a test program (Reference 5) to study the effects of burning
synthetic fuels in g gas turbine, H-Coal 210-480 F distillate, 300-500 F
distillate, 450-650 F distillate, and atmospheric bottoms were combusted in
a subscale gas-turbine-like combustor. No significant handling problems
were encountered, though fuel quality (water content, suspended particles,
etc.) did cause some minor problems. The NO levels, were measured and
compared to No. 2 distillate. The results that showed approximately 30 to
60 ppm more NO was emitted by the H-Coal fuels. Smoke levels were similar
to the No. 2 distillate, but did show some increase as hydrogen content
decreased or aromaticity increased.
Later tests (Reference 8) on a full scale combustor were conducted
with the H-Coal 210-480°F distillate. This fuel had a nitrogen content of
0.17 percent (the No. 2 fuel had no nitrogen) yet showed a NOX increase of
only 20 ppm. Smoke values for the H-Coal were generally lower than for the
No. 2 fuel oil except at exhaust temperatures above 1750 F.
F.2.3 COMBUSTION/HANDLING PROPERTIES OF EDS COAL LIQUIDS
A study by Stone and Webster (Reference 15) concluded that existing
oil-fired boilers can be converted to accept EDS fuels. Only minimal
changes to existing equipment would be required for four of the five types
of EDS fuels. The required changes are associated primarily with the
incompatability of coal liquids and petroleum-derived fuels. When EDS
fuels are mixed with petroleum fuels, a thick sludge forms that will cause
problems in fuel oil lines, tanks, heaters, and other equipment.
Therefore, all types of EDS fuels will require either separate fill lines,
or the lines must be washed with a mutually compatible flux stock from
dedicated storage tanks.
The viscosity of three types of EDS fuels studied was less than that
of a No. 6 petroleum fuel; therefore, these types will require less
heating for pump transfer. One type had a viscosity similar to that of No.
F-23
-------
6 petroleum fuel oil and will not require any changes to existing stream
tracing or heaters. TheQviscosity of the Type 3 EDS fuel, which is a blend
of streams above £he 700 F plus boiling range, will require heating to
approximately 260 F during storage and transfer and 400 F during firing to
satisfy burner viscosity requirements of 150 saybolt second universal
(SSU). Some existing piping systems, steam tracing, in-tank heaters, and
station fuel oil heaters will have to be replaced.
EDS fuels may degrade if the liquid is exposed to air and stored at
temperatures of 100 F or higher for several months. Nitrogen blanketing of
floating roofs would be required in existing storage tanks for two types of
EDS fuels.
Quinlan (Reference 16) discussed the results of combustion studies
conducted by Exxon on various fuel oils (Table F-10). The combustion tests
were run in a 50 hp Cleaver-Brooks firetube package boiler with a nominal
firing rate of 15 gallons per hour. Smoke emissions, particulate
emissions, and gaseous NO emissions were measured. The Cleaver-Brooks
combustion tests indicate that heavy coal liquids burn easily and cleanly.
No problems were encountered in tests areas such as flame light off, nozzle
fouling, or shutdown, although the test period was relatively short. The
coal liquids burned very clean as judged by comparing their smoke emissions
to those for conventional petroleum fuels. The petroleum fuels were a
regular sulfur fuel oil (2.2 weight percent S) and a low-sulfur fuel oil
(0.5 weight percent S). The coal liquids were an Illinois coal derived
400 F plus blend and a minimal 400-1000 F blend which represents the EDS
product without the liquids from FLEXICOKING.
The primary conclusion from these data is that Illinois coal liquids
burn with smoke levels equal to or lower than petroleum fuel oils at all
levels of excess air. Over the range of excess air from 10 to 30 percent,
the coal liquids gave a Bacharach Smoke Number of 1 or less. Below 10
percent excess air, Bacharach Smoke Numbers for the coal liquids increased
more slowly than for petroleum fuels so that even at excess air levels of
only a few percent, tolerable smoke emissions were obtained in this test.
A second conclusion is that except at very low excess air levels (5
percent), the presence of the heavier liquids from FLEXICOKING at about 25
weight percent of the 400 F plus blend did not significantly affect the
smoke levels from the coal liquids.
Table F-10 compares particulate and N0x emissions for the EDS liquids
with those from the low sulfur and regular sulfur fuel oil. The
particulate emissions from the coal liquid fuels were very low -- roughly
half from the low-sulfur fuel oil, which is itself a low particulate fuel.
The regular sulfur fuel is actually more typical of a conventional heavy
fuel. It has four or five times as many particulate emissions as the coal
liquids. As a frame of reference, the current New Source Performance
Standards for power generation boilers for ash content is about 0.18 weight
percent. The regular sulfur fuel oil was about equal to that standard, and
coal liquids were well below it.
F-24
-------
TABLE F-10. EDS FUEL OIL COMBUSTION TEST PARTICULATE AND NOY EMISSIONS^18)
__ ..
Emission Type
Particulate Emissions
Total Particulates,
mG/SCM
Total Particulates,
Wt. % on Fuel
Ash Content of Sample,
Wt. %
NOx Emissions
Nitroqen, Wt. % on Sample
Flue gas N0« Concentration,
PPM {Corrected to 3% 0?)
Heavy Fuel Oil
Liquids
400-1 000°F 400°F
27 33
0.03 0.04
0.027 0.03
0.55 0.81
490 580
Petroleum
Fuel
LSFO
50
0.06
0.02
0.13
300
Oils
RSFO
131
0.17
0.08
0.44
440
Distillate Fuel Oils
Raw Mild H/T Severe H/T
400-800°F 350-650°F 350-650°F No. 2 Fuel Oil
_ _ _ _
_ _ _ _
—
163 60 51 57-64
I
ro
en
LSFO = Low Sulfur Fuel Oil
RSFO = Regular Sulfur Fuel Oil
-------
The particulate level for coal liquids is low because that practically
all of the carbon burns out. Total mass emissions from the coal liquids
are only slightly than the fuel ash content; whereas, in the petroleum
fuels they are significantly higher. This difference probably reflects the
volatility of the heaviest materials in the fuels. All of the coal liquid
is volatile, so it evaporates and burns as a vapor. The petroleum fuels
contain asphaltenes, which are not volatile and form droplet residues that
burn out very slowly.
The N0x emissions from the coal liquids were higher than those from
the petroleum fuel oils, reflecting their higher fuel nitrogen content.
The two coal liquids gave 490 and 580 ppm respectively, compared with 300
and 400 ppm for the two petroleum fuel oils. All of these values are
higher than the current New Source Performance Standard for oil-fired
utility boilers, which is about 225 ppm. However, the coal liquids just
about meet the expected new standard for coal-fired boilers, which is 550
ppm.
Another potential EDS product is a distillate fuel oil. This product
ranges from a raw solvent (nominally 400/800 F) to a severely hydrotreated
350/650 F product (hydrogen consumption: 300 SCF/bbl) (Table F-ll). The
major difference between EDS coal liquid middle distillates and
conventional petroleum products is that raw and mildly hydrotreated
products have lower API gravity and hydrogen content because of their
highly aromatic nature. Raw Illinois coal middle distillate products, both
400/800 F and 350/650 F, exhibit high sulfur and nitrogen contents compared
with conventional petroleum products. Studies have shown that even mild
hydrotreating (500 SCF/bbl) substantially reduces both sulfur and nitrogen.
With severe hydrotreating (3000 £CF/bbl), the low ppm levels indicated for
the severly hydrotreated 350/650 F are attained.
The combustion performance of the coal middle distillates was
evaluated by burning studies on a conventional 1 gallon-per-hour domestic
oil burner unit. Raw and hydrotreated coal liquids were run in a domestic
gun burner and the results were compared with results using a petroleum No.
2 fuel oil at the same combustion conditions. The coal liquids burned
cleanly, giving essentially the same smoke number as the petroleum fuel at
a given level of excess air. The severely hydrotreated coal liquids (30
API gravity) could be substituted for the petroleum No. 2 fuel without any
adjustment of the air shutter. It is likely that this fuel could be used
interchangeably with a petroleum No. 2 in the field. N0x emissions (Table
F-10) from the raw EDS liquids were significantly higher than those from
the petroleum or from the hydrotreated coal liquid; this can be attributed
to the higher nitrogen content of the raw coal liquids. At the present
time there are no NO emission standards for domestic fuel combustion.
A
A study (Reference 5) of the combustion characteristics of EDS process
liquid and EDS process liquid without the 650 F fraction was conducted
using a sub-scale gas-turbine-like combustor. NOX and smoke levels were
F-26
-------
TABLE F-ll. PROPERTIES OF EDS FUEL
I
IN3
Properties
Handling Characteristics
Gravity, ° API
Flash, °F
Pour, °F
Viscosity, ssu at 100°F
Sediment, Wt. %
Combustion Properties
Higher Heating Value, Btu/lb
Carbon Residue (10% Bottoms),
Wt. %
Hydrogen Content, Wt. %
Environmental Considerations
Sulfur, Wt. %
Nitrogen, Wt. %
Middle Distillate
Fuel Oil
Raw
400-800°F
18
196
-5
38
19000
3.0
10
0.3
0.2
Hydrotreated ASTM Specification
350/650°F No. 2 Fuel Oil
30 30 Min.
120 100 Min.
-70 20 Max.
32 33 Min.
20500
0.01 0.35 Max.
13
0.004
<0.001
Heavy Fuel Oil
Raw EDS 400°F+
Liquid
0
196
40
158
16,700
151,000
0.8
1.0
ASTM Specification
No. 6 Fuel
—
140 Min.
60 Max.
40 - 300
—
—
—
-------
slightly higher than for the No. 2 distillate. Over the range of exhaust
temperatures, excess NO ranged from 60 to 75 ppm for the whole process
liquid, which had a nitrogen content of 0.08 percent.
F.3 CHEMICAL CHARACTERIZATION OF INDIRECT COAL LIQUIDS COMBUSTION
No data on the emissions from combustion of Fischer-Tropsch or Mobil
M-Gasoline are available. However, the uncontrolled emissions from
methanol fueled automobiles are reasonably well documented. Tests indicate
that CO emissions are approximately the same as from the gasoline engine
and NO emissions are somewhat lower. Hydrocarbon emissions are about the
same and are dominated by unburned methanol fuels. Polynuclear aromatic
emissions are reduced to as little as one-tenth; but aldehydes,
particularly formaldehyde, are increased three- to five-fold. No lead or
sulfur are emitted (Reference 16).
F.4 CHEMICAL CHARACTERIZATION OF LOW/MEDIUM
Tables F-12 and F-13 list the components of the flue gas from the test
burner that was burning the low-Btu product gas characterized in Appendix
E. It can be seen that a wide variety of trace and minor elements can be
emitted as a result of burning low-Btu gas. Chemical analysis also
indicated that organic species present in the test burner flue gas were
more highly carboxylated than those in the uncombusted product gas. The
aromatics present were relatively simple ring systems, and the fractions
contained fewer indications of nitrogenous compounds than the product gas.
Benzo(a)anthracene was specifically identified in the test burner flue gas
at 450 yg/SCM. Benzo(a)pyrene, dibenzo(a, hjanthracene, and 7, 12
dimethylbenzo(a)anthracene were present in the product gas but did not
appear in the fraction of the test burner flue gas that was analyzed
(Reference 17).
F-28
-------
TABLE F-12. Gaseous
Low-Btu
Species Analysis Summary:
Test Burner Flue Gas1 '
Analysis Test Burner Flue Gas
Major Components (% _+ 2 )
C02 5.4 ±2.2
H? NDa
02 + Ar 16. +_ 4.8
N2 77.8 + 5.2
CO ND
CH4 ND
Sulfur Species (Vppm ± 2 )
H2S NDa
COS NDa
S02 103 _+ 122
CS2 2.8 _+ 5.1
Total volatile sulfur NR
C -C Hydrocarbons (Vppm _+ 2 )
CH4 ND
C2H6 ND
C2H4 ND
C^ + isomers NDa
C4 + isomers NDa
Cc + isomers NDa
o
Cg -i- isomers
Nitrogen Species (Vppm +_ 2 )
NH3 <0.005
HCN 1.0 +_ 1.0
Metal Carbonyls (Vppm) NR
ND not detected; NR no results.
One detectable measurement out of four analyses.
F-29
-------
TABLE F-13. Trace and Minor Element Compositi
Low-Btu Test Burner Flue Gas^ '
ons of
Element
Aluminum
Antimony
Arsenic
Barium, Beryllium, Bismuth
Boron
Bromine
Cadmium
Calcium
Ceri urn
Cesium
Chlorine
Chromium
Cobalt
Copper. Dysprosium, Erbium,
Fluorine, Gadolinium
Gallium
Germanium, Gold, Hafnium,
Holmium
Iodine
Iridium
Iron
Lanthanum
Lead
Lithium
Lutetium
Magnesium
Test
Particulate
ug/SCM
1.9
<0.3
0.40
<120
0.16
0.096
0.024
>120
0.34
0.0066
0.99
0.59
0.14
1.2
1.0
0.29
0.20
>120
0.40
3.2
1.3
>120
Burner Flue
Vapor
pg/SCM
14
<11
86
4.6
3.8
0.34
>0.2
660
0.28
1.1
32
36
130
8.1
99
<1
0.20
0.66
190
0.44
12
<0.07
16
Gas
Total
yg/SCM
16
<11
86
>120
0.44
0.44
>0.2
>780
0.62
1.1
33
37
130
9.3 Europium
100
<1.3
0.66
>310
0.84
15
<1.4
>130
(Continued)
F-30
-------
TABLE F-13. (CONTINUED)
Element
Manganese
Mercury
Molybdenum
Neodymi urn
Nickel
Niobium
Osmium
Pal ladium
Phosphorus
Platinum
Potassium
Praseodymium
Rhenium
Rubidium
Ruthenium
Samarium
Scandium
Selenium
Silicon
Silver
Sodium
Strontium
Sulfur
Tantalum
Tell urium
Terbium
Thallium
Test
Particulate
ng/SCM
0.44
0.0011
<0.2
0.025
1.4
0.037
6.8
>120
0.013
0.15
<0.01
<0.3
>120
0.92
>120
3.5
120
Burner Flue
Vapor
yg/SCM
17
16
18
44
0.07
160
1.3
370
<0.2
<0.04
<130
170
a
23
2.0
a
Gas
Total
ug/SCM
17
16
18
0.025
45
.10
170
1.3
>490
0.013
<.35
<.05
<130
>290
0.92a
>140
5.5
120a
(Continued)
F-31
-------
TABLE F-13. (CONTINUED)
Element
Thorium
Thulium
Tin
Titanium
Tungsten
Uranium
Vanadium
Ytterbium
Yttrium
Zinc
Zirconium
Test
Particulate
yg/SCM
0.074
2.7
<.04
0.15
<0.02
0.99
0.25
Burner Flue
Vapor
ug/SCM
1.4
18
3.4
12
12
Gas
Total
yg/SCM
1.5
21
<.04
3.6
<0.02
13
12
SpOo impinger solution.
S202 impinger solution.
Not listed: test burner flue gas .01 g/SCM
SCM at 25°C (770°F) and 101 kPa (1 atm), dry basis.
F-32
-------
REFERENCES
1. Southern California Edison and Paraho Oil Shale Demonstration,
Inc. "Emission Characteristics of Paraho Shale Oil as Tested in a
Utility Boiler". EPRI AF-709, March 1978.
2. Bennett, R. L. and K. T. Knapp. "Chemical Characterization of
Particulate Emissions from Oil-Fired Power Permits". Fourth
National Conference on the Environment, Cincinnati, Ohio, October
T97F:
3. Cato, G. A., L. J. Muzio and R. E. Hall. Proceedings from the
Stationary Source Combustion Symposium, Volume III -- Field
Testing & Surveys. EPA-600/2-76-152c, June 1976.
4. Finch, S. and S. Morris. "Consistency of Reported Health Effects
of Air Pollution". Brookhaven National Laboratory, BNL-21808.
5. Singh, P. D. et al. "Combustion Effects of Coal Liquid and Other
Synthetic Fuels in Gas Turbine Combustors." Proceeding of ASME
Conference. New Orleans, LA, March 10-13, 1980, ASME Publication
80-GT-67.
6. Leavitt, C., et al. "Environmental Assessment of an Oil-Fired
Controlled Utility Boiler." EPA 600/7-80-087,'April, 1980.
7. Carter, W. A., H. J. Buening, and S. C. Hunter. "Emission
Reduction on Two Industrial Boilers with Major Combustion
Modifications". EPA-600/7-78-099a, June 1978.
8. Bauserman, G. W., C. J. Spengler, A. Chohn. "Combustion Effects
of Coal Liquid and other Synthetic fuels in Gas Turbine
Combustors Part II: Full Scale Combustor and Corrosion Tests".
Presented at the Gas Turbine Conference and Products Show, New
Orleans, Louisiana, March 10-13, 1980.
9. Mobil Research and Development Corporation. "Upgrading Coal
Liquids for Use as Power Generation Fuels". EPRI Report AF-1255,
December 1979.
10. Cabal, A. V., et al. "Utilization of Coal-Derived Liquid Fuels
in a Combustion Turbine Engine". Proceedings of National
American Chemical Society. Miami Beach, Florida, September
TSTE:
11. Mansour, M. N. "Factors Influencing NO Production During the
Combustion of Gulf's SRC II." So. California Edison Final Report
Number 79-RD-7, March 1979.
F-33
-------
12. Oak Ridge National Laboratory. "Draft Environmental Impact"
Statement: Solvent Refined Coal-II Demonstration Project. Fort
Martin, West Virginia, May 19, 1980.
13. Babcock & Wilcox Co. "Characterization of SRC II Fuel Oil".
EPRI Report No. FP-1028, June 1979.
14. KVB, Inc. "Combustion Demonstration of SRC II Fuel Oil in
Tangentially Fired Boiler". EPRI FP-1029, May 1979.
15. Electric Power Research Institute. "Effectiveness of Gas
Recirculation and Staged Combustion in Reducing NO on a 560-MW
Coal-Fired Boiler". EPRI FP-257, September 1976.x
16. Timourian, H. and F. Milanovich. "Methanol as a Transportation
Fuel: Assessment of Environmental and Health Research".
UCRL52697, Lawrence Livermore Laboratory, Livermore, California,
1979.
17. Kilpatrick, M. P. et al. "Environmental Assessment: Source Test
and Evaluation Report; Wellman-Galusha (Ft. Snelling) Low-Btu
Gasification". EPA-600/7-80-097, U. S. Environmental Protection
Agency, Washington, D. C., May 1980.
18. Quinlan, C.W., and C. W. Siegmund. "Combustion Properties of Coal
Liquids from the Exxon Donor Solvent Process". Proceedings of
American Chemical Society Symposium Combustion of Coal and
Synthetic Fuels.Anaheim, California, March 14, 1978.
F-34
-------
APPENDIX G
HEALTH EFFECTS TEST RESULTS FOR
SYNTHETIC FUEL PRODUCTS
TABLE OF CONTENTS
G.I Shale Oil Products G-3
G.I.I Crude Shale Oil G-3
G.I.2 Middle Distillates G-4
G.I.3 Gasoline 6-11
G.I.4 Residual Fuel Oil G-ll
G.2 Direct Coal Liquids G-ll
G.2.1 SRC II G-ll
G.2.1.1 Naphtha 6-12
G.2.1.2 Light Fuel Oil G-14
G.2.1.3 Heavy Distillate 6-15
G.2.2 H-COAL Products 6-17
G.2.2.1 Naphtha 6-17
G.2.2.2 Fuel-Oil 6-19
G.2.3 Exxon Donor Solvent 6-19
6.3 Indirect Coal Liquids 6-19
6.3.1 Fischer-Tropsch Gasoline G-21
6.3.2 Mobil-M Gasoline G-21
6.3.3 Methanol G-21
G.4 Health Effects of Coal Gases G-22
G.4.1 SNG G-22
G.4.2 Low-/Medium-BTU Gases G-23
G.5 Synthetic Fuel Combustion Products G-23
6-1
-------
TABLES
Number Page
G-l Mutagenicity of Shale Oil and Petroleum Crudes
In Ames/Salmonella Test G-4
G-2 Comparison of the Mutagenicity of Solvent Refined Coal
Materials, Shale Oils, and Crude Petroleums in Salmonella
typhimurium TA 98 G-5
G-3 Distribution of Mutagenic Activity in Shale-Derived Oils ... G-6
G-4 Cytotoxicity of Fossil Fuel Materials and Metals in
Cultured Vero Cells G-7
G-5 Effect of Solvent Refined Coal Materials, Shale Oil and
Petroleum Crudes on Cloning Efficiency and Transformation
Frequency in Syrian Hamster Embryo Cells G-8
G-6 Skin Tumor Incidence in Mice at 456 Days of Exposure to
Fossil Fuel Materials or Known Carcinogens G-9
G-7 Mouse Skin-Painting Initiation/Promotion Study G-10
G-8 Guinea Pig Skin Sensitization Test Results for Refined Shale
Oil Products G-ll
G-9 Comparison of the Acute and Subchronic Toxicities of SRC
Materials in the Female Wistar Rat G-13
G-10 Maternal and Fetal Toxicity in Rats Following Dosing with
SRC II Materials from 12 to 16 Days of Exposure. G-16
G-ll Ames Test Results for Petroleum and H-Coal Products G-18
G-12 Health Effects Test Results for H-Coal Fuel Oils G-18
G-13 Distribution of Mutagenic Activity in H-Coal G-20
G-2
-------
G.I SHALE OIL PRODUCTS
The major commerical shale oil products are anticipated to include
crude shale oil, middle distillates (jet fuel and diesel fuel), and
residual fuel oil. Several different shale oil products are available from
the EPA/DOE Fossil Fuels Research Material Facility at the Oak Ridge
National Laboratory, and each available product is being tested for health
and ecological effects. Some results of the from health effects tests are
available and are reviewed in this appendix, but no results from ecological
effects testing are yet available.
G.I.I CRUDE SHALE OIL
The relative toxicity of crude shale oil has been investigated in a
battery of tests including mutagenicity, cytotoxicity, cell transformation,
epidermal carcinogenesis, and acute oral toxicity tests. Tables G-l, G-2,
and G-3 present results of Ames Salmonella tests conducted on crude retort
shale oil, crude in situ shale oil, and crude petroleum oils. The data
presented in these tables indicate that crude retort shale oil and in-situ
shale oil are slightly more mutagenic than crude petroleum oil.
In mammalian cell culture studies, shale oil was one of the most
cytotoxic fossil-derived materials tested and was considerably more
cytotoxic than either of the crude petroleum oils tested (Table G-4). As
shown in Table G-5, shale oil also produced a higher percentage (3 percent)
of transformed cell colonies than crude petroleum (0.2 to 0.4 percent).
Skin-painting studies with mice indicate that crude shale oil is more
potent than crude petroleum at inducing tumors. As shown in Table G-6, the
incidences for the high- and medium dose shale oil group are 100 percent
and 82 percent, respectively; the incidence for the high- and medium-dose
group for Wilmington crude are lower at 42 and 7 percent. The minimum
latency period is also lower for shale oil than for Wilmington crude.
Table G-7 presents the results at 180 days of a mouse skin-painting study
in which doses corresponding to the "medium" dose in the study discussed
above were administered to 30 mice. Although the shale oil crudes were
similar in tumor initiating activity to the petroleum crude, the Paraho
crude (retort) was a little more potent than the South Louisiana crude, and
the Geokinetics crude (in situ) was a little less potent than the South
Louisiana crude (Reference 1).
Acute toxicity studies measured the oral rate LD^Q for shale oil at
9.22 mg/kg of body weight. The LD^r, for crude petroleum was reported at
>12 mg/kg (Reference 1). Based on the LDrQ values, both products would
be considered slightly toxic in comparison with other organic chemicals
(Reference 11).
The preliminary limited data which are available for crude shale oil
indicate that shale oil may pose a slightly more severe hazard with regard
to mutagenicity (Ames test results) and carcinogenicity (cell transfor-
mation and epidermal carcinogenesis studies) than crude petroleum. Further
G-3
-------
TABLE G-l. MUTAGENICITY OF SHALE,AND PETROLEUM CRUDES IN
AMES/SALMONELLA TESTUJ
Material S. Typhimurium Strain (with activation)
TA 1535 TA 1537 TA 1538 TA 98 TA 100
So. Louisiana Crude Na N N N 0.02
Paraho Crude N 0.07 0.55 0.70 0.50
(12.0) (41.9) (29.7) (2.8)
Geokinetics Crude in situ
N
0.03
(4.3)
0.10
(6.0)
0.10
(5.7)
0.9
(1-7)
aN No response
Revertants per g (average). Comparisons of revertant(s) per g
values among strains can be misleading because there values are
strongly influenced by spontaneous frequencies.
GThe maximum average number of revertants observed expressed as a
multiple of the average spontaneous reversion frequency.
studies, some of which are currently underway, will confirm or refute these
preliminary findings.
G.I.2 MIDDLE DISTILLATES
The U.S. Navy tested petroleum JP-5, petroleum DFM (diesel fuel
marine), shale JP-5, and shale DFM for primary dermal irritation, primary
eye irritation, and dermal sensitization. They are also currently testing
shale-derived JP-5 and DFM for acute and sub-chronic toxic effects from
vapor exposure. Samples of these petroleum- and shale-derived products are
available for testing from the Fossil Fuels Research Program at the Oak
Ridge National Laboratory, and several researchers are conducting a variety
of tests for toxicity and ecological effects (Reference 5).
G-4
-------
TABLE G-2. COMPARISON OF THE MUTAGENICITY OF SOLVENT REFINED COAL
MATERIALS, SHALE OILS, AND CRUDE PETROLEUMS IN SALMONELLA
TYPHIMURIUM TA 98^ '
Materials Revertants/ug of Material
SRC II
Heavy distillate 40.0^23
Middle distillate 0.01
Light distillate 0.01
SRC I
Process solvent 12.3 +_ 1.9
Wash solvent 0.01
Light oil 0.01
Shale Oil
Paraho-16 0.60 _+ 0.19
Paraho-504 0.59 _+ 0.13
Livermore L01 0.65 _+ 0.22
Crude Petroleum
Prudhoe Bay <0.01
Wilmington <0.01
Pure Carcinogens
Benzo(a)pyrene 114 _+ 5
2-Aminoanthracene 5430 + 394
G-5
-------
TABLE G-3. DISTRIBUTION OF MUTAGENIC ACTIVITY IN SHALE-DERIVED OILS
(3)
Sample
Shale Oil in situ
Paraho Shale Oil
HDT-Paraho Shale Oil
Wilmington Crude Oil
Recluse Crude Oil
Total
(Rev/Mg)a
178
390
0
5
6
Mutagenic Activity Distribution (%)
Neutral
54
31
0
100
100
Acids
2
0
0
0
0
Bases
42
69
0
0
0
Other
2
0
0
0
0
Determined from the linear portion of a dose-response curve with strain
TA 98
The only test results available are from the Navy's skin and eye
irritation tests. According to these tests, all four of the fuels tested
would be considered non-irritants; there is no irritation hazard to humans
who come into contact with them. However, one would expect that frequent
or prolonged contact would cause depletion of skin oils, making the skin
more susceptible to irritation (Reference 6). In primary eye irritation
tests, only shale DFM produced any signs of irritation. One rabbit of six
that were tested by applying 0.1 ml of undiluted fuel to one eye developed
a very mild redness and discharge 24 hours following treatment. At 48
hours, the redness and discharge disappeared, and the eye had returned to a
normal state of appearance (Reference 6).
A repeated insult skin-sensitization study using guinea pigs was
carried out to predict whether allergic contact dermatitis would result in
humans after skin contact with the test materials (Table G-8). The size as
well as the intensity of the irritation was evaluated semi-quantitatively
and reported as the sensitization response. The sensitizing potential of
the test material was estimated from the number of animals having at least
a mild sensitization response. Twenty animals were tested. The test
material's sensitizing potential was judged "slight" if one to three
animals were sensitized, "moderate" for four to ten sensitizations, and
"severe" for 11 to 20 sensitizations.
G-6
-------
TABLE G-4. CYTOTOXICITY OF EQSSIL FUEL MATERIALS AND METALS
IN CULTURED VERO CELLSU;
Material RPE5Q Dose (yg/ml)a
SRC II
Heavy distillate 30
Middle distillate 200
Light distillate 180
Shale Oil (S-ll) 50
PNA fraction 40
Basic fraction 50
Neutral fraction 200
Petroleum
Prudhoe Bay Crude 350
Wilmington crude 190
Diesel oil #2 250
Metals
Cadmium chloride 0.3
Zinc Chloride 6.8
Lead chloride 37
RPE[-n dose required to reduce number of colony-producing cells to
50% Of control value.
G-7
-------
TABLE 6-5. EFFECT OF SOLVENT REFINED COAL MATERIALS, SHALE OIL AND PETROLEUM
CRUDES ON CLONING EFFICIENCY?AND TRANSFORMATION FREQUENCY IN
SYRIAN HAMSTER EMBRYO CELLSv;
Concentration (vig/ml) Percent of Relative
to produce maximum colonies cloning
Material transformation frequency transformed efficiency (%)
Dimethyl sul foxide 0
Heavy distillate (SRC-II) 20
Shale oil (LERC)a 10
Basic fraction 10
PNA fraction 50
Prudhoe Bay crude 200
Wilmington crude 100
Benzo(a)pyrene 20
0 100
6.8 33
2.7 34
8.9 77
3.4 74
0.4 23
0.2 48
11.0 42
aLaramie Energy Research Center
G-8
-------
TABLE G-6.
SKIN TUMOR INCIDENCE IN MICE AT 456 DAYS OF EXPOSURE TO FOSSIL
FUEL MATERIALS OR KNCWN CARCINOGENS(2)
cr>
i
Treatment
Control - Untreated
Vehicle control
(acetone)
Heavy distillate
SRC- 1 1
Light distillate
SRC- 1 1
Shale Oil
Crude Petroleum-
Wilmington
Benzo(a)pyrene
2- Aminoanthracene
Dose
(mg/application)
22.8
2.3
0.23
20.0
2.0
0.2
21.2
2.1
0.21
16.8
1.7
0.17
0.05
0.005
0.0005
0.05
0.005
Tumor
Incidence
0/49
0/47
49/49
47/47
6/48
1/44
1/46
0/41
38/38
41/50
0/45
20/45
3/45
0/46
50/50
44/46
0/50
25/32
0/49
Minimum
Latency (days)
56
72
282
410
427
95
148
260
282
106
232
115
Median .
Latency (days)
95
294
213
351
;;;;
143
358
379
Maximum
Latency (days)c
147
372
;;;;
409
193
::::
^Number with tumors/rumber at risk
cDays to 50% tumor incidence
Days to 100% tumor incidence
-------
TABLE G-7. MOUSE SKIN-PAINTING INITIATION/PROMOTION STUDY
CD
I
Sample
S. Louisiana Crude
Paraho Crude
Geokinetics Crude In Situ
Occidental Crude In Situ
Number of
mice with
tumors
lasting
30 days
5
9
2
0
Total
Number of
tumors
lasting
30 days
7
17
2
0
Average
Number of
tumors/
tumor
bearing
mouse
1.4
1.9
1.0
0
Number of
days to
first
mouse with
tumor
71
59
92
0
Days of promotion: 180
29 surviving mice in group
-------
TABLE 6-8. GUINEA PIG SKIN SEN.SITIZATION TEST RESULTS FOR REFINED
SHALE OIL PRODUCTS (6)
Number
Showing
Response
Fuel
Petroleum JP-5
Petroleum DFM
Shale JP-5
Shale DFM
24 Hr.
5
7
2
8
48 Hr.
6
9
4
4
Sensitization
Potential
Moderate
Moderate
Slight
Moderate
Mean
Reaction
Score
(24 Hr.)
70
71
50
46
Sensitization
Response
Mild
Mild
Mild
Mild
G.I.3 GASOLINE
There appears to be no health or ecological effects testing being
conducted on gasolines derived from shale oil.
G.I.4 RESIDUAL FUEL OIL
There appears to be no health or ecological effects testing being
conducted on residual fuels produced from shale oil.
G.2 DIRECT COAL LIQUIDS
The available health effects tests results for the major products from
three direct coal liquefaction processes, SRC II, H-coal, and Exxon Donor
Solvent, are summarized in this section.
6.2.1 SRC II
The developers of the SRC II process anticipate marketing three major
products: naphtha, light fuel oil, and heavy fuel oil (Reference 9).
Researchers at Battelle Memorial Institute in Richland, Washington have
conducted a battery of health effect tests on these three fractions. In
addition, the EPA/DOE Fossil Fuels Research Materials Facility at the Oak
Ridge National Laboratory has an SRC II fuel oil blend on which several
researchers are currently conducting health and ecological effects tests
(Reference 5). So far only limited test results are available.
6-11
-------
G.2.1.1 Naphtha
Petroleum-derived naphtha poses its greatest hazard through vapor
inhalation. Accidental or intentional ingestion of naphthas and volatile
solvents also poses a major hazard. Skin contact generally results in
reversible skin irritation (References 4, 7).
Table G-2 shows that the SRC II light distillate (naphtha)
demonstrated no mutagenic activity in Ames testing (Reference 2). At
another laboratory, a naphtha from South Louisiana crude petroleum was also
found to be nonmutagenic when subjected to the Ames test (Reference 1). In
cytoxicity tests conducted on cultured mammalian cells (VERO), a dose of
180 g/ml was required to produce a 50 percent reduction in relative plating
efficiency (RPE). Thus, SRC II light distillate was one of the least
cytotoxic fossil-derived materials tested (Table G-5) (Reference 2).
Researchers at Battelle Memorial Institute are conducting skin-painting
studies on mice (Reference 2). As shown in Table G-6, only one mouse in
the medium- and high-dose groups exposed to light distillate had developed
a grossly observed tumor at 456 days after initiation. No tumors had
developed in the low-dose group. Thus, preliminary data from this study
indicate that the tumorigenic activity of the light distillate is extremely
low (Reference 2). Petroleum naphtha has also been shown to exhibit only
very slight tumor initiating activity in mouse skin-painting studies
(Reference 1).
Table G-9 presents the results of oral acute toxicity tests at LD^Q,
the orally administered dose (g/kg of body weight) required to kill 50
percent of the adult Wistar rats in three days. Subchronic toxicity was
determined by administering the product once daily for five consecutive
days. The difference between the acute and chronic LD^Q values indicates
that either the material or the effects of the light distillate are
cumulative (Reference 2). On the basis of the acute LD^Q, (2.3 9/kg),
SRC II naphtha would be considered moderately toxic. Investigators also
report that SRC II naphtha, unlike petroleum naphthas, shows some degree of
acute toxicity through skin absorption at a fairly high dose level (1.6
g/kg body weight) (Reference 1).
A developmental toxicity study was conducted in which SRC II
distillates were administered to pregnant rats. Such studies are conducted
because the prenatal organism is often more sensitive to toxic compounds
than are adults. Comparedd to the control group, the experimental group
should no significant increase in the incidence of malformation of fetus
for dams receiving the light distillate during the first 7 to 11 days of
gestation. The frequency of prenatal mortality, however, was increased in
dams receiving the light distillate during days 12 through 16 of the
gestation period (Table G-9). The doses that were required to produce
increases in prenatal mortality approach the doses that produce maternal
toxicity effects. Thus, this test does not indicate a greatly enhanced
sensitivity of the embryo or the fetus to SRC II light distillate
(Reference 2).
G-12
-------
TABLE G-9. COMPARISON OF THE ACUTE AND SUBCHRONK TOXICITIES OF SRC
MATERIALS IN THE FEMALE WI STAR RAT
Material
Wash solvent (SRC I)
Light distillate (SRC II)
Process solvent (SRC I)
Light oil (SRC I)
Heavy distillate (SRC II)
Middle distillate (SRC II)
Shale Oil
Diesel oil
Crude petroleum
Acute, Subchronic
LD50 LD50b
0.57 (1.66)C (1.50)c
2.30 0.96
2.81 1.04
2.90 2.41
2.98 1.19
3.75 1.48
9.22
11.8
12
The materials were administered one time by gavage for the acute
toxicity studies. For the subchronic studies, materials were gavaged
once daily for five consecutive days.
LD^Q is defined as the dose in grams per kilogram of body weight
required to kill 50% of the animals. For the acute toxicity study,
this value represents a single dose while for the subchronic studies,
the value represents a daily dose.
'The LDcQ values in parentheses are for materials diluted in corn oil.
All other values are for undiluted material.
G-13
-------
Very few directly comparable health effects tests exist for SRC-II and
petroleum naphthas. Ames test and skin-painting studies indicate that the
two naphthas are not significantly different in their mutagenic or
tumorigenic activity. The SRC II naphtha, however, may present a more
severe acute toxicity hazard when absorbed through the skin.
6.2.1.2 Light Fuel Oil
As is the case with naphtha, vapor inhalation is the most significant
method of exposure to middle distillate petroleum products (e.g., No.2 fuel
oil). The result may be dizziness, coma, collapse, or death. Exposure to
high levels of vapors is generally followed by complete recovery, although
permanent brain damage has been reported. Toxicity via ingestion is
considered to be moderate, and contact with the skin typically causes
reversible irritation (Reference 7). In general, the toxicity of middle
distillate petroleum products is related to the content of benzene and
other aromatic hydrocarbons.
In the Ames test, SRC II middle distillate demonstrated no measurable
mutagenic activity (Table G-2). The Ames test was also conducted on four
distillation fractions of a crude petroleum. The two middle fractions were
designated "light gas oil" and "mid-gas oil". The light gas oil did not
demonstrate mutagenic activity, but the mid-gas oil did (Reference 1). In
separate testing, mutagenic activity toward Salmonella typhimurium was not
observed when a No.2 fuel oil was tested with activation by rat or trout
liver extract (References).
The mammalian cell cytotoxicity of the SRC II middle distillate is
approximately the same as for the light distillate and the SRC II middle
distillate is one of the least cytotoxic fossil-derived materials tested
(Table 6-4). The test data also indicate that SRC II middle distillate is
slightly more toxic than the analogous petroleum-derived product, diesel
oil No.2.
The acute toxicity of the SRC II middle distillate is greater than
that of diesel oil; thus, it may pose a somewhat more severe ingestion
hazard (Table G-9). In comparison with the LDcQ of other industrial
chemicals, the SRC II middle distillate would Be considered moderately
toxic while the petroleum-derived diesel oil would be considered slightly
toxic. The differences in values for the acute LDcg (3.75 g/kg) and the
subchronic ID™ (1.48 g/kg) indicate that either the material or the
effects are cumulative (Reference 2). The SRC II middle distillate is
reported to be capable of causing skin burns (Reference 9) and, thus,
appears to be more acutely toxic when absorbed through the skin than
petroleum-derived middle distillates.
In developmental toxicity tests, administration of the SRC II middle
distillate during the first 7 to 11 days of gestation did not significantly
increase the incidence of malformations. Fetal weight losses and prenatal
mortalities were only observed at doses producing symptoms of maternal
6-14
-------
toxicity. The frequency of prenatal mortality was increased when the test
material was administered at 12 to 16 days of gestation (Table G-10). As
was the case for SRC II light distillate, test results suggest that the
risk for the fetus is only slightly greater than for the mother (Reference
2).
While more comparable test results exist for the middle distillates
than for the light distillates, the data base is still small and the
results must be considered preliminary. Neither SRC II middle distillate
nor petroleum No.2 fuel oil appear to be mutagenic. The cytotoxicity of
SRC II and petroleum middle distillates is similar, although the SRC II may
be slightly more cytotoxic. The SRC II middle distillate also appears to
be somewhat more acutely toxic when ingested and absorbed through the skin.
G.2.1.3 Heavy Distillate
Little information on the toxicity of petroleum-derived fuel oils is
available, although some testing for carcinogenicity has been conducted.
Testing indicates that residual fuels oils are carcinogenic to rabbit skin
and mouse cervicovaginal epithelium (Reference 10). An "industrial fuel
oil" (API Gravity 8.3) was found to be a relatively potent carcinogen in
mouse skin painting studies (Reference 11). Tests conducted on several
petroleum fractions indicate that the carcinogenic materials in petroleum
are concentrated in the fractions boiling above 675-700 F (References 11,
6). Therefore, it is reasonable to expect some correlation between the
carcinogenic potency of petroleum-derived fuel oils and the extent to which
a fuel contains fractions boiling above 675 or 700 F.
The SRC II heavy distillate proved to be the most mutagenically active
of the SRC II distillates when subjected to Ames testing (Table G-2). The
heavy distillate was fractionated by a solvent extraction procedure into an
acidic, basic, and neutral fraction as well as a basic and neutral tar
fraction. The highest specific mutagenic activity (number of revertants
per microgram of material) was found in the basic fraction although the
basic and neutral tar fractions exhibited considerable activity as well.
Because the tars constitute a larger portion of the mass of the heavy
distillate, they contribute a larger share of the heavy distillate's total
mutagenic activity than the basic fraction, despite the basic fraction's
higher specific activity. Further chemical analysis and Ames testing
identified several primary aromatic amines as the compounds responsible for
the mutagenic activity, including aminonaphthalenes, aminoanthracenes,
aminophenanthrene, aminopyrenes, and aminochrysenes (Reference 2).
In the mammalian cell cytotoxicity tests, SRC II heavy distillate was
one of the most toxic fossil-derived materials tested (Table G-4). It also
was one of the most active compounds in effecting cell transformations
(Table G-5). SRC II heavy distillate was one of the most potent substances
G-15
-------
TABLE G-10.
MATERNAL AND FETAL TOXICITY IN RATS FOLLOWING DOSING WITH
SRC II MATERIALS FROM 12 TO 16 DAYS OF EXPOSURE?*)
0
1
1— '
en
Agent
Corn Oil
Arocloi-k
Light
Distillate
Middle
Distillate
Heavy
Distillate
Dosea
(g/ kg/ day)
_ _
0.11
0.28
0.56
0.84
1.12
1.41
1.69
0.33
0.65
0.98
1.30
1.63
1.96
0.37
0.73
1.10
Number
Dosedc
14
13
11
12
14
6
7
5
9
11
9
6
6
3
15
13
12
Percent
Deadc
0
0
9
8
43
67
86
80
0
9
11
33
67
100
0
0
17
Number
Pregnant
at 21 d.g.
12
10
8
9
7
1
1
1
9
7
8
4
2
0
4
10
9
Weight
Gain
to 21 d.g.d
148 * 31
101 ± 24
116 * 36
101 37
113 ± 27
32 0
50 ± 0
112 i 0
127+43
149 32
118-40
126 ± 19
94 ± 36
--
129 * 31
85 ± 23
76 ± 23
Percent of
Implants
Resorbed6
I1'
7
4,
23f
41
_
_.
0
5
7
20f
0,
64f
--
9.
66f
69*
Litters
With
Resorptions
1
5
4
4
3
--
20
0
5
5
5
0
2
--
7
9
9
Percent
Malformed
Fetuses6'^
0
0
2
0
1
—
1
0
3
0
0
0
0
--
1
74
60
Litters
With
Fetuses9
0
0
1
0
1
--
0
0
1
0
0
0
0
--
2
5
6
Fetal
Weight
at 21 d.g.h
5.4 / 0.5
4.3 / 0.6
5.5 / 0.5
5.5 / 0.5
5.4 / 0.5
--
4.7 / 0.2
5.1 / 0.3
5.8 / 0.6
5.8 / 0.6
5.1 / 0.4
4.9 / 0.5
4.5 / 0.4
5.3 / 0.5
4.3 / 0.7
4.3 / 0.5
Administered by gavage once daily for five consecutive days; if undiluted, 0.1-1.2 ml given per 300 g body weight.
Diluted in corn oil and 1 ml given per 300 g body weight.
Includes both pregnant and nonpregnant adult females.
Body weight gain between 0 and 21 days of gestation (d.g.}; mean * SD.
Calculated on a per fetus rather than a per litter basis; includes resorbed and dead implants.
One or more litters with all implants resorbed.
^Combination of soft itssue and skeletal malformations.
Pooled means of each litter.
or more dams delivered prematurely; implant data incomplete and not included.
-------
tested for epidermal carcinogenesis. The two rate groups given the highest
dosages had a 100 percent tumor incidence rate {Reference 2). Microscopic
examination revealed that 33 of the 39 mice with tumors had malignant
tumors; 18 of the 39 had microscopic evidence of metastasis. Three mice
had papillomas only (Reference 12).
Acute toxicity studies indicate that the LD^Q value for the heavy
distillate is approximately the same as those for the middle and light
distillates (Table G-9) (Reference 2). Administration of heavy distillate
to the experimental group at 7 to 11 days of gestation did not
significantly increase the incidence of malformations over that of the
control group. Fetal weight and prenatal mortality was only affected at
doses producing maternal toxicity effects. More severe fetal effects were
observed when the test material was administered at 12 to 16 days of
gestation. The frequency of prenatal mortality was increased in the
absence of signs of maternal toxicity. An increased incidence of
malformations was also observed; however, this was accompanied by inhibited
maternal weight gains. It appears that the risk for the fetus is only
slightly greater than for the mother (Reference 2).
Skin-painting tests indicate that both petroleum-derived industrial
fuel oils (Reference 10) and SRC II heavy distillate (Table G-6) pose
considerable skin carcinogenicity hazards. The limited test results
suggest that precautions should be taken to prevent human exposure to SRC
II heavy distillate. Unfortunately, comparable tests have not been
conducted on analogous petroleum products. Thus, an assessment of the
relative hazards posed by the two products is not possible at this time.
G.2.2 H-COAL PRODUCTS
Naphtha and fuel oil are two major H-Coal products expected to enter
the market; these two products are discussed in the following paragraphs.
Although several researchers are currently conducting health and ecological
effects tests, only limited results are available to date.
G.2.2.1 Naphtha
H-Coal naphtha can be produced either as a primary naphtha from the
H-Coal syncrude operation or by hydrocracking heavier primary H-Coal
products such as gas oil (Reference 13). Calkins et al (Reference 1)
tested naphtha from the syncrude mode for mutagenicity and tumor-inducing
potential. The coal-derived naphtha was found to be non-mutagenic (Ames
test) as was a petroleum derived naphtha (Table G-ll). No data is
available on the mutagenicity of naphtha produced by hydrocracking heavier
H-Coal products.
The primary H-Coal naphtha contains levels of sulfur, nitrogen, and
oxygen that are high compared to petroleum-derived naphthas or naphtha
produced by hydrocracking H-Coal gas oil (Reference 13). The phenols
content (3.1 percent by volume) of primary H-Coal naphtha indicates that
G-17
-------
TABLE G-ll. SUMMARY: AMES TEST,RESULTS FOR PETROLEUM AND H-COAL
PRODUCTSu;
Material
Test Results
South Louisiana Crude Petroleum
Naphtha
Light Gas Oil
Mid-gas Oil
Residue
Crude Oil
Nonmutagenic
Nonmutagenic
Mutagenic
Mutagenic
Mutagenic
H-Coal Liquid Syncrude Mode
Naphtha
Light Gas Oil
Atmospheric Still Overheads
Atmospheric Still Bottoms
Vacuum Still Overheads
Nonmutagenic
Nonmutagenic
Nonmutagenic
Mutagenic
Mutagenic
TABLE G-12. HEALTH EFFECTS TEST RESULTS FOR H-COAL FUEL OILS
(15)
Tests
Raw
Hydrotreatment
Low Med.
High
Mutageni
city
(Ames)
Tumor Production
Cy tot oxi
city
High
Medium
Medium
High
No Response
Medium
High
No Response
Medium
No
No
Low
Response
Response
6-18
-------
thiS would product pose a significant hazard if spilled into an aquatic
environment. The phenolic content of most petroleum products is less than
1 percent (Reference 14).
Ames test results indicate that H-Coal naphtha and petroleum naphtha
are both mutagenically inactive. Primary H-Coal naphtha's relatively high
phenol content suggests that it is likely to be more toxic to aquatic
organisms than petroleum naphthas. There is insufficient information
available to compare the relative toxicities of the primary H-Coal naphtha,
naphtha from hydrocracked H-Coal gas oil, and petroleum naphtha.
G.2.2.2 Fuel-Oil
Atmospheric still bottoms can be hydroprocessed into acceptable No.2
fuel oil blending stocks (Reference 13). Untreated atmospheric still
bottoms exhibit mutagenic activity in Ames testing (Tables G-12 and G-13),
but data on the mutagenicity of the hydrotreated H-Coal blending stocks is
not available.
Health effects tests for middle distillates from H-Coal operated in
the fuel oil mode have been conducted and are summarized in Table G-12.
Comparable test results from petroleum middle distillates are not
available.
6.2.3 EXXON DONOR SOLVENT
The major Exxon Donor Solvent products expected to enter the market
include naphtha and fuel oil. Health effects tests are currently being
conducted on EDS products but no results are yet available (Reference 1).
G.3 INDIRECT COAL LIQUIDS
The major indirect coal liquefaction products expected to be marketed
include Fischer-Tropsch gasoline, Mobil-M Gasoline, and methanol motor
fuels. Only two health effects tests have been conducted on a Fischer-
Tropsch gasoline, and none have been conducted on Mobil-M gasoline. The
effects of methanol have been studied for many years, and new risks would
be attributable to exposure to a larger population because of the new use
of methanol.
The toxic properties of petroleum gasoline are similar to those of
naphthas and solvents. Vapors pose the most serious hazard. Exposure to
extremely high levels may result in dizziness, coma, and collapse. Such
exposures are usually followed by complete recovery, although permanent
brain damage following massive exposure has been reported (Reference 16).
High vapor levels may also act as a simple asphyxiant (Reference 7).
Gasoline can also cause irritation and other disturbances if it comes
in to contact with the eyes. The acute toxicity by ingestion is considered
to be moderate (Reference 7). Skin-painting studies revealed that gasoline
was not carcinogenic to the skin of mice (Reference 11). In general, the
6-19
-------
TABLE G-13. DISTRIBUTION OF MUTAGEMIC ACTIVITY IN H-COAL
(3)
ORNL
Ref. No.
1601
1602
1603
1604
Sample
H-Coal Distillate (raw)
HOT H-Coal Distillate (low severity)
HOI H-Coal Distillate (medium severity)
HOT H-Coal Distillate (high severity)
H-Coal ASB (syn)
H-Coal VSOH (syn)
H-Coal VSB (syn)
H-Coal ASOH (FO)
H-Coal ASB (FO)
H-Coal VSOH (FO)
H-Coal VSB (FO)
Composite Crude Oil
Louisiana-Mississippi Sweet Crude Oil
Wilmington Crude Oil
Recluse Crude Oi 1
Total
(Rev/mg)a
350
540
210
0
1,230
4,100
2,200
0
140-
4,100
6,000
175
75
5
6
Mutagenic Activity Distribution (%)
Neutral
63
100
100
0
63
76
25
0
0
74
13
95
100
100
100
Acids
0
0
--
0
0
0
0
0
0
0
0
2
0
0
0
Bases
37
0
--
0
37
24
60
0
100
26
85
3
0
0
0
Other
0
0
--
0
—
—
—
--
--
--
--
0
0
0
0
CD
I
Determined from the linear portion of a dose-response curve with strain TA-98
-------
toxicity of gasoline is related to its content of benzene, a suspected
human carcinogen (References 17, 18), and other aromatic hydrocarbons.
Other additives, such as tetraethyl lead, could also alter the overall
toxicity of gasoline (References 4, 7).
G.3.1 FISCHER-TROPSCH GASOLINE
Fischer-Tropsch (F-T) gasoline has been tested for its carcinogenic
potential. Skin cancer was not induced by the application of F-T gasoline
to the skin of mice or rabbits. Injection into the thigh of rats did,
however, cause carcinomas attributable to the treatment in two of the 15
tested rats (Reference 19).
Examination of the chemical composition of F-T gasoline indicates the
absence of N and S heterocyclic compounds and an aromatics content that is
only slightly lower than in petroleum gasoline (see Appendix E,
Section E.3.1). The induction of cancer in rats by injection indicates
that F-T gasoline may pose a hazard by accidental parenteral introduction
(e.g., through a cut in the skin). Similar testing has apparently not been
conducted on petroleum gasoline. The similarity in chemical composition
and the result of skin-painting studies indicate that the health effects
from F-T and petroleum gasoline are not likely to be significantly
different. No testing of F-T gasoline for ecological toxicity has
apparently been conducted.
G.3.2 MOBIL-M GASOLINE
No health or ecological effects tests have been conducted on Mobil-M
gasoline (Reference 20). The absence of heterocyclic compounds and the
similarity between Mobil-M gasoline and petroleum gasolines in aromatics
content provide no reason to believe that the two products will cause
significantly different health or ecological effects (see Appendix E,
Section E.3.2).
G.3.3 METHANOL
The use of methanol as a fuel would normally result in low and
moderate exposure via inhalation and skin absorption of the people involved
with the transportation and delivery of the fuel. Accidental exposures to
high levels via inhalation and skin absorption could also be expected.
Relatively few exposures via ingestion are anticipated.
Once methanol enters the body it is rapidly dispersed throughout the
body. The effects of methanol include inebriation, vomiting, abdominal
pain, visual disturbances, shortness of breath, delirium, unconsciousness,
coma, and death (Reference 16). Individual susceptibility varies, but a
dose lethal to humans is generally from two to eight ounces (Reference 4).
Methanol is metabolized and excreted very slowly (Reference 16). This
suggests that the effect of chronic low-level exposures may be cumulative
G-21
-------
and produce eye and central nervous system damage equal to that which
results from higher level acute exposures. The extent to which this occurs
is not known (Reference 21).
G.4 HEALTH EFFECTS OF COAL GASES
Several laboratories are conducting toxicity studies on coal gases;
however, very few results are yet available. Most of these studies are
being sponsored by the U.S. Department of Energy. For example, the Argonne
National Labortory is conducting toxicity studies on process streams from
high-Btu coal gasification. The Morgantown Energy Technology Center and
the Lovelace Inhalation Toxicology Research Institute are conducting
toxicological evaluation of effluents and process streams from low-Btu
gasifiers. The results of tests performed by Arthur D. Little, Inc. on
low-Btu coal gas are available and are briefly summarized in the following
paragraphs.
G.4.1 SNG
Examination of the chemical composition of SNG reveals three
components with specific toxic effects: carbon monoxide, hydrogen sulfide,
and metal carbonyls. The remaining components, methane, ethane, carbon
dioxide, nitrogen, argon, and hydrogen, do not have specific toxic effects
but can act as simple asphyxiants. Signs of asphyxia could result if their
combined concentration is allowed to exceed 20 to 30 percent by volume in
inspired air (Reference 22).
Carbon monoxide acts as a chemical asphyxiant. However, standards for
pipeline gas generally require the CO content to be less than 1000 ppmv.
It is anticipated that crude SNG would be sufficiently upgraded to meet
this criteria. Concentrations of hydrogen sulfide, as low as 20 to 150
ppm, can act as an irritant to the eyes and respiratory tract
(Reference 7). Prolonged exposure may result in pulmonary edema and higher
concentration exposures can result in central nervous system depression and
death (Reference 22). Considering the low concentration in a typical SNG
(0.2 ppmv), hydrogen sulfide does not appear to pose a significant hazard.
The metal carbonyls that are potentially present in SNG include nickel
tetracarbonyl, Ni(CO)4, and iron pentacarbonyl, Fe(CO)c, (Reference 23).
Nickel carbonyl is an extremely toxic substance; a lethal exposure for
humans is estimated to be 30 ppm for 30 minutes (Reference 24). Chronic
exposure to nickel carbonyl has been implicated epidemiologically to cancer
of the lungs and nose (Reference 22). It is also a recognized carcinogen
in animals (Reference 25). Iron carbonyl is also highly toxic; however, it
is less toxic than nickel carbonyl (Reference 7). The toxic effects of
inhaling iron carbonyl include dizziness, nausea, difficult breathing, and
possibly death (Reference 7).
No direct biological effects test results are available yet for SNG.
Based on chemical composition, it does not appear that hydrogen sulfide
levels will be high enough to pose a health hazard, and carbon monoxide
G-22
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levels are not likely to exceed those in natural gas. It is possible that
SNG will contain metal carbonyls; however, the extent to which they will
actually be produced in commercial-scale plants is yet to be determined.
Unless metal carbonyls are present, it does not appear that SNG will cause
significantly different health effects than natural gas.
G.4.2 LOW-/MEDIUM-BTU COAL GAS
EPA studies have involved testing of particulates and resin extracts
from low-Btu gas from a Wellman-Galusha gasifier (Reference 26) using
liqnite. The particulates and extracts were obtained using the Source
Assessment Sampling System (SASS) which consists of a series of impingers,
filters, and resins for collecting of particulates and gaseouse impurities.
The extracts were subjected to the Ames mutagenicity test, cyctotoxicity
testing, and an acute toxicity test. No mutagenic activity was exhibited
by the extracts, although they were extremely toxic to the tester strains
and could only be tested at concentrations less than 10 yl/plate. In vitro
toxicity test results using Wl-38 human lung fibroblast cells indicated
moderate cytotoxicity. Rats exhibited no signs of toxic or pharmacological
effects when the extracts were orally administered. No mortality was
recorded, indicating the oral ID™ for each test substance is greater than
lOg/kg (Reference 26). DU
G.5 SYNTHETIC FUEL COMBUSTION PRODUCTS
Mutagenicity and cytotoxicity tests conducted on SASS train extracts
of sampled test burn flue gas are the only health effects test results
available on the combustion products of synthetic fuels. The gas being
combusted was from a low-Btu Wellman-Galusha gasifier using lignite. No
mutagenic activity nor cytotoxicity was exhibited by the extracts
(Reference 26). Mutagenicity tests on shale-derived DFM (diesel fuel
marine) are currently being conducted (Reference 5).
G-23
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REFERENCES
1. Calkins, W.H., Deye, J.F., King, C.F., Hartgrove, and D.F. Krahn.
Synthetic Crude Oils. Carcinogenicity Screening Tests.
C004758-2, Department of Energy, Washington, D.C. , 1979.
2. Battelle Pacific Northwest Laboratory. "Biomedical Studies on
Solvent Refined Coal (SRC II) Liquefaction Materials: A Status
Report." U.S. Department of Energy Contract EY-76-C-06-1830,
PNL-3189, October 1979.
3. Rao, T.K. and J.L. Epler. Second Symposium, "In Vitro Toxicity
of Environmental Comples Mixtures," Wil liamsburg, Va. March,
1980.
4. Gleason, M. N., et al . Clinical Toxicology of Commercial
Products, Third Edition. The Williams and Wil kins Company, 1969.
5. Griest, W.H., D.L. Coffin, and M.R. Guerin. "Fossil Fuels
Research Matrix Program." ORNL/TM-7346 June 1980.
6. U.S. Navy, Information provided to D.D. Evans of TRW, March 1980.
7. Sax, N.I. Dangerous Properties of Industrial Materials, Fourth
edition. Reinhold Publishing Company, 1975.
8. Payne, J.F., I. Martins and A. Rahimtula. "Crankcase Oils: Are
They a Major Mutagenic Burden in the Aquatic Environment?"
Science, 200: 329-30, 1978.
9. Pittsburg and Midway Coal Mining Co. "Demonstration Plant
Marketing Plan. SRC II Demonstration Project." Prepared for
U.S. Department of Energy. FE-3055-T13, July 31, 1979.
10. Bingham, E., R.P. Trosset, and D. Warshawsky. "Carcinogenic
Potential of Petroleum Hydrocarbons, A Critical Review of the
Literature." Journal of Environmental Pathology and Toxicology,
3: 483-563,
11. Kettering Laboratory. "Investigation of the Potential Hazards of
Cancer of the Skin Associated with the Refining of Petroleum.
Final Report." API Research Project MC-1, October 20, 1959.
12. Battelle Pacific Northwest Laboratory. "Appendix to Biomedical
Studies on Solvent Refined Coal (SRC II) Liquefaction Materials:
A Status Report." PNL-3189-Appendix, December, 1979.
13. Gim, Tan and A.J. de Rosset. "Hydrocracking of H-Coal Process
Derived Gas Oils," I
FE-256623, November"
G-24
Derived Gas Oils," Upgrading of Coal Liquids: Interim Report
1978.
-------
14. Giddings, J.M., B.R. Parkhurst, C.W. Gehrs, and R.E. Millemann.
"Toxicity of a Coal Liquefaction Product to Aquatic Organisms."
Bull. Environmental Contam. Toxicology, 25, 1-6 (1980).
15. Kolber, A.R., R.S. DeWaskin, and D.R. Greenwood. "lexicological
Studies on Coal-Derived Synthetic Fuels Products and By
products." Prepared for U.S. Environmental Protection Agency,
Industrial Environmental Research Laboratory by Research Triangle
Institute,. Research Triangle Park, North Carolina. August
1980.
16. Cornish, H.J. "Solvents and Vapors," Toxicology, The Basic
Science of Poisons. First Edition, L.J. Casarett and J. Doull,
Eds., MacMillan Publishing Co., Inc. New York 1976.
17. Carcinogen Assessment Group's (CAG) List of Carcinogens. U.S.
Environmental Protection Agency, July 14, 1980.
18. International Agency for Research on Cancer, IARC Monographs on
the Evaluation of Carcinogenic Risk of Chemicals to Man, WHO
Publications Center, Albany, New York, Volume 7, p. 203 1974.
19. Hueper, W.C. Experimental Carcinogenic Studies on Hydrogenated
Coal Oils II; Fischer-Tropsch Oils, Industrial Medicine and
Surgery. October 1956. pp.459-462.
20. Mobil Research and Development Corporation, Telephone
conversation with Max Schreiner and Dr. Woo Young Lee July 28,
1980.
21. Timourian, H. and F. Milanovich. "Methanol As A Transportation
Fuel: Assessment of Environmental and Health Research."
UCRL52697, Prepared by Lawrence Livermore Laboratory Linden U.S.
Department of Energy Contract Number W-7405-ENG-48. June 18,
1979.
22. Casarett, L.J. "Toxicology of the Respiratory System,"
Toxicology, The Basic Science of Poisons, First Edition. L.J.
Cararett and J. Doull, Eds. MacMillan Publishing Co., Inc. New
York, 1976.
23. C.F. Braun and Company. "Carbonyl Formation in Coal Gasification
Plants." Prepared for Energy Research and Development
Administration and American Gas Association, FE-2240-16, December
1974.
24. American Industrial Hygiene Association: Nickel Carbonyl.
25. International Agency for Research on Cancer. IARC Monographs on
the Evaluation of Carcinogenic Risk of Chemicals to Man. WHO
Publications Center, Albany, New York, Volume II, p. 75, 1976.
G-25
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26. Kilpatrick, M.P., et al. "Environmental Assessment: Source Test
and Evaluation Report, Wellman-Galusha (Ft.Snelling) Low-Btu
Gasification." EPA-600/7-80-097, U.S. Environmental Protection
Agency, Washington D.C., May 1980.
27. Pittsburgh and Midway Coal Mining Company. Response to Public
Hearings on SRC-II Demonstration Plant, Correspondence from
Pittsburgh and Midway to U.S. DOE, August 1980.
G-26
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-81-025
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
Environmental Aspects of Synfuel Utilization
5. REPORT DATE
March 1981
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
8. PERFORMING ORGANIZATION REPORT NO.
M. Ghassemi and R. S. Iyer
9. PERFORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
One Space Park
Redondo Beach, California 90278
10. PROGRAM ELEMENT NO.
CCZN1A
11. CONTRACT/GRANT NO.
68-02-3174, W.A. 18
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Task Final; 3/80-2/81
14. SPONSORING AGENCY CODE
EPA/600/13
15. SUPPLEMENTARY NOTES IERL.RTP project officer is Joseph A. McSorley, Mail Drop 61,
919/541-2827.
16. ABSTRACT
The report gives results of a review of the environmental concerns relating
to the distribution, handling, and end use of synfuel products likely to enter the mar-
ket place by the year 2000, and assigns priority rankings to products from the stand-
point of environmental concerns. The report: reviews available data on the physical,
chemical, and health effects characteristics of synfuel products and the environmen-
tal significance of such characteristics; analyzes the potential environmental impacts
and regional implications associated with the production and end use; and ranks the
products from the standpoint of environmental concerns and mitigation requirements.
Review results indicate that: (a) wide-scale transportation, distribution, and end use
of certain synfuel products can present significant threats to the environment and the
public health; (b) based on gross characteristics, synfuel products appear to be sim-
ilar to petroleum products, but detailed characterization data are not available to
judge their relative safety; and (c) synfuel test and evaluation programs currently
underway or planned provide excellent opportunities for the collection of some of
the required environmental data.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATi Field/Group
Pollution
Assessments
Coal
Liquefaction
Coal Gasification
Shale Oil
Pollution Control
Stationary Sources
Synfuels
Environmental Impacts
13B
14 B
08G
07D
13H
13. DISTRIBUTION STATEMENT
Release to Public
19. SECURITY CLASS (This Report)
Unclassified
21. NO OF PAGES
402
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
G-27
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